ML17215A431

Reload Safety Rept. App I Withheld (Ref 10CFR2.790)

ML17215A431
Person / Time
Site:	Saint Lucie
Issue date:	06/30/1984
From:	FLORIDA POWER & LIGHT CO.
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ML17215A430	List: ML17215A429 ML17215A431 ML17301A108
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NUDOCS 8406110290
Download: ML17215A431 (437)

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RELOAD SAFETY REPORT ST. LUCIE 2 CYCLE 2 OPERATION AT 2560 MWTH DOCKET: 50-389 LICENSE: NPF-l6 I

JUNE l984 840bii0290 840b04 '

PDR ADOCK 05000389, i'>>

P .

PDR

TABLE OF CONTENTS

~Pa e 1.0 Introduction and Summary 2.0 Reac tor Design 2,1 Mechanical Design 2.1.1 Fuel Design 2.1.2 Replacement CEA Design 2.2 Thermal Design 2.3 Chemical Design 2.4 Nuclear Design 2.4. 1 Fuel .Management 2.4.2 CEA Configuration, Bank Vorths and Shutdown Margin 4 2.4.3 Power Distribution 5 2 4.4 E5ected CEA 5 2.¹.5 Dropped CEA 5 2.4.6 Scram Reactivity 5 2.4.7 Augmentation Factors 5 2.4.8 Analtyical Input to In-Core Meausrements 6 2.4.9 Uncertainties in Measured Power Distributions 6 2.4.10 Nuclear Design Methodology 6 2 ' Thermal Hydraulic Design 6.

2.5.1 DNBR Analysis 6 2.5.2 Effects of Fuel Rod Bowing on DNBR Margin 6 3 0 r Powe Capability and Design Basis Event Evaluation 29 3 ~ 1 Power Capability 30 3.2 Non-LOCA Safety Analysis 32 3.2.0 Introduction 32 3.2.0.1 Methods of Analysis 32 3.2.0.2 Mathematioal Models 33 3.2.0.3 Input Parameters and Analysis Assumptions 33 3.2.'1 Increase in Heat Removal by the Secondary System 45 3.2.1.1 Decrease in Feedwater Temperature 45 3.2.1.2 Increase in Feedwater Flow 54 3.2.1.3 Inoreased Main Steam Flow 63 3.2;1.4 Inadver tent Opening of a Steam Generator Safety Valve or Atmospheric Dump Valve ,72 3.2.1.5a Steam System Piping Failures:

Inside Containment Pre-Trip Power Excursions 83 3.2.1.5b Steam System Piping Failures: .

Outside Containment Pre-Trip Power Excursions 93 3.2.1.5c Steam System Piping Failure, Post-Trip Power Peaks, 103

TABLE OF CONTENTS (continued)

~Pa e 3.2.2 Decrease in Heat Removal by the Secondary System 122 3,2.2 ~ 1 Loss of External Load 122 3.2.2.2 Turbine Trip 122 3.2.2.3 Loss of Condenser Vacuum 122 3.2.2.4 Loss of Offsite Power to the Station Auxiliaries (LOAC) 131 3.2.2.5 Loss of Normal Feedwater 142 3.2.2.6 Feedwater Line Break Event with A Loss of AC 143 3 0203 Decrease in Reactor Coolant Flow Rate 156 3.2.3.1 Partial Loss of Forced Reactor Coolant Flow 156 3.2.3.2 Total Loss of Forced Reactor Coolant Flow 157 3.2.3.3 Single Reactor Coolant Pump Shaft Seizure/Sheared Shaft 167 3.2.4 Reactivity and Power Distribution Anomalies 175 3.2.4.1 Uncontrolled Control Element Assembly Withdrawal from a Subcritical or Low Power Condition 175 3.2.4.2 Uncontrolled Control Element Assembly Withdrawal at Power 183 3.2.4.3 CEA Drop Event 193 3.2.4.4 CVCS Malfunction (Inadvertent Boron Dilution) 202 3.2.4.5 Startup of an Inactive Reactor Coolant Pump Event 206 3.2.4.6 Control Element Assembly EJection 207 3.2,5 Increase in Reactor Coolant System Inventory 213 3.2.5 ' CVCS Malfunction - Pressurizer Level Control System (PLCS) Mal-function with a Simultaneous Closure of the Letdown Control Valve to the Zero Flow Position 213 3.2.5 2 Inadvertent Operation oi the ECCS During Power Operation 222 3.2.6 Decrease in Reactor Coolant System Inventory 223 3.2.6.1 Pressurizer Pressure Decrease Events:

Inadvertent Opening of the Pressurizer Relief Valves 223 3.2.6.2 Small Primary Line Break Outside Containment 232 3.2.6.3 Steam Generator Tube Rupture with a Concurrent Loss of Offsite Power 240 3-2.7 Miscellaneous 3.2.7.1 'symmetric Steam Generator Events 251'51 3 ' LOCA E vents 260 331 Large Break LOCA ECCS Performance 260 3.3.1 ' Introduction and Sumnary 260 3.3 ~ 1.2 Method of Analysis 260 3.3.1.3 Results 261 3.3.1.4 Conclusions 262

TABLE OF CONTEHTS (continued)

~Pa e 3 e302 Small Break LOCh ECCS Performance 343 3.3.2.1 Introduction and Suaeary 343 3.3.2.2 Method oi Analysis 343 3.3,2,3 Results 344 3.3.2.4 Conclusions 345 303+3 Post-LOCh Long Term Cooling ECCS Performance 384 3.3.3.1 Introduction and Suneary 384 3.3.3.2 Method oi Analysis 384 3.3.3.3 Results 385 3.3.3.4 Conclusions 386 3.3.4 Containment Systems Analysis 395 3.3.4.1 Containment Structure 395 3.3.4.2 Subcompartment Analysis 400 3.3.4.3 Hydrogen Build-Up Analysis 401 3.4 Hydraul ic (Blardom) Loads on the Reactor Vessel

'nterns ls Under Faulted Conditions F 406 3.4 ~ 1 Introduction ¹06 3.4.2 Analytical Procedures 406

'.4.3 Initiating Events 406

~

3,4 4 Hydrodynamic Forcing Functions 406 3.4.5 Parameters of Interest 407 3.4.5.1 Lateral Pressure Difference Across Vessel Annulus 407 3.4.5.2 Lateral Drag Force on Control Element Assembly (CEA) Shrouds ¹07 3.4.5.3 Pressure Difference Across Core Support Barrell (CSB) Wall ¹08 3.4.5.4 Core Axial Pressure Difference 408 3.4.6 Results 408 3.4.6.1 Vessel Inlet Break 408 3.4.6.2 Vessel Outlet Break 408 3.4.6.3 Steam Generator Inlet Break ¹09 3,¹,7 Conclusions 409 4.0 Technical Specification Changes 420 5.0 References 428

TABL~ OF COHTZPS (con+inued)

Appendix I: Uncertainties Derived-by'he E',U Methodology

1. 0 Introduction AI-1 2.0 Component Uncertainty Developnent Methodology'.1 AI-1 St. Iucie Unit 2 Uncertainties AI-1 3.0 KU Thermal pydraulic Methodology AI-2 3.1 State Parameters AI-2

3. 2 Response Surface AI-2 3.3 ~tatisti~t Derived IG)>SR Limit AI-2 4.0 KU Transient Analysis Method ol~ AI-3 4- 1 General 'trategy AI-3 4.2 Analysis Performed for Evaluation og ROPI for Limiting EB~m AI-3 4.2.1 Loss of Coolant Flow Event (4 Pump LOP) Al-3 4.2.2 Full Length CZA Drop Event

(&M Drop) AIQ 4.2.3 Results of SCU Safety Analyses AI-5

5. 0 Conclusions AI-5

6. 0 References AI-5

1.0 XHPRQKUCZICS AND SOBhhRY i

cperation of St- Iacie Unit 2 during its second fuel cycle at a ~er rating of 2560 l%t with an indicated full 549M. St -~e g~ inlet tettperature of Unit 2 is presently ay~ting in its first fuel cycle utilizing Batch A, B, and C fuel asserrblies at a licensed core pan r level

~

of 2560 l4tt.. Operatica of Cycle 1 has ccntinued at or near licensed ~er and it is presently esthaated that Cycle 1 will texndnate on or about October 21, 1984. Operation of Cycle 2 is scheduled to cxmamce in Savenher 1984. The core will mnsist of 137 presently ~mating Batch B and C assarbIies together with 80 fresh Batch D assemblies.

St *!I 7 f Ct*

length ranging fnxn 8,250 to 10,000 ZPPH and the Cycle 2 loaiing pattern has been designed to acammdate this range of Cycle 1 lengths. In perfoxming analyses of postulated accidents, deteaakning lind.ting safety system settings and establishing limiting conditions for cperation, values of key paranaters were chosen to assure that, ected ccnditicas are enveloped within the abc'ycle 1 en3point range. The analyses presented herein will acxxmmdate a Cycle 2 1'~ up to 10,000 EEP8.

The evaluations of the Cycle 2 reload core characteristics have been examined with r~xmt to the safety analyses presented within the St. Lucie Unit. 2 FBhR (Reference 1), hereafter referred to as the "reference cycle".

In all cases, it ~

has been cxmcluded that the revised analyses presented in this report ccc;rtixme to acceptable results.

%here dictated by variations fran Cycle 1, proposed modificatices to the plant Ta9mical Specifications are provided and are )ustified by the analyses report~ herein.

2 0 REhCKR ZESIGH The rrechanical design of .the Batch. D reload fuel asserrblies is identical t'o that of the Core 1 fuel asserrblies (Reference 1) with the exception of the design features li.sted belch. So changes in mechanical design bases have occurrer3 since the original fuel design. Bogever, the Ba~ D design inccmporates a nurrber of refinerrM.nts for the purpose of izmreasing rrargins for shoulder gap change and fuel assenbly cpaeth. The speci.fic changes are discussed in the follcwing paragraphs.

1. The fuel rod ove~rll lerx~ has been reduced by 0.3 inches, ~ch is achieved by shortening the plenum lenr~. The reduction of fuel rod length results in additional shoulder gap c1earance.

2. The fuel asserrbly guide tube has been changed fran cold worked to annrmled material. The change to annealed material will result in a lcwer garth rate of the fuel asserrbly.

3. The overall length of the annealed guide tubes has been increased by 0.4 inches. This ixmreese of guide tube length pxeduces a coxresporxhng raising of the uppew end fitting and results in additicnal shoulder gap clearance.

The aachanical design of the Core 1 fuel (Bate% B and C) to be loaded for Cycle 2 was discussed in Reference 1. Carbusticn Engineering (C-E) has reviewed all the aachanical changes to the Batch D design and has concluded that the revised design naets all the mechanical design bases applied to the original fuel design as specifi+,in Reference 1.

. C-E has performed analytica1 predictions of cladding creep collapse time for aU. St. Lucie Unit 2 fuel ba~es that will be irradiated during Cycle 2 and has concluded that the collapse resistance of a11 fue1 rods is suffi,cient to preclude collapse during their design lifetime. This lifetime will not be exceeded by the Cycle 2 duraticn (Table 2.1-1). The collapse analysis utilised the CEPAH catputer code (Reference 2) and included caoservative izput values of intrmml pressure, cladding dimansices, clar3ding terrperature and neutxon flux.

I All fuel assenblies to be installed in Caatrol ElerIMnt Assenbly locations either have or will have stairQ.ess steel sleeves installed in the guide tubes in order to rrritigate guide tube wear.

All hatches of fuel were reviewed for r3irransioual char~ using the methods described in Reference 3. All clearances were Sound to be adaymte during Cycle 2. Bc+ever, as discussed in Reference 1, inspection of other 0-E 16xl6 fue1 asserrblies has shcam, in sane cases, higher rates of shaulder gap change than predicted by the correlates described in Reference 3. In addition, the St. Dlcie Unit. 2 fuel design and plant cpmaticn are different frcxn those for other C-E fuel. Therefore, .any necessary additional analysis and/ar han3ware modifications will be perfccrmd prior to startup of Cycle 2 cperaticn to assure that. the shoulder gap clearance behreen fuel rods and fuel asserrbly end fittings is a3erpmte.in accordance with Amendrnant 4 to the Facility Operating License,

4 C

2.1.2 lacettw'nt CEK Desi Twelve nev "reduce&strength" full-length Control Eleaeat Asseablies (Cps) will be used far= Cycle 2 operation in place of existing Cycle 1 "full strength" CEAs. Eight of these replaced "full stx~~th" full length CEAs will be placed in the ~~ part lcm~ CEL locations far use in Cycle 2 cperatian. The mechanical design of these "reduced strength" Cps are identical to the initial care full-lena~ Cps with the exception of individual elect poison aaterial content as shown in Table 2.1-2.

There are no changes in the mechanical design Mmes far the CEAs fnxn those listed in Reference l.

The theaml perfoxnance of a cxxgasite fuel pin that envelcpes the varims fuel assemblies present in Cycle 2 (fuel Batches B, C, and D) has been evaluated using the FATES3 version of the fuel evaluation nedel (References 4 and 5), including the NRC inclosed grain size restriction (Reference 6).

'Xhe analysis was perforated with a goer history that, envelcpes the paver and burlap levels representative of the peak pin at each burnup interval, fnm beginning of cycle (BOC) to end of cycle (HK) bun~. The burnup range analyzed is in excess of that expected at the EGC2.

The PATES3 pnrer~enterline malt limit was deter@i.ned for Cycle 2 by taking scxne credit far the decrease in pew er peaking which is characteristic of highly burned fuel. Since a gradual decrease in the calculated paver-to-melt (due to a decrease in the fuel melt teaperature) also acccxrpanies burnup, the most limiting paver-to-centerline melt has been found to occur within an interaadiate burnup range. Using ccnservative estimates of the burnup point at which the ~er peaking begins to decrease and the rate at which it decreases far Cycle 2, the most limiting pnrer~enterline mlt has been deterred to be in excess of 22 k /ft.

The aatallurgical recpureaants of the fuel clahRing and the fuel assembly structural mmrbers far the Batch D fuel are identical to those of the ather fuel batches to be included in Cycle 2. Thus, the chanical or metallurgical performance of the Batch D fuel will ranain unchanged fran the perfornance of the Cycle 1 fuel (Reference 1).

The Cycle 2 care will ccesist of the aurrbers and types of assemblies fran the various fuel batches as described in Table 2.4.1-1. The primary changes to the care for Cycle 2 are the replacenent of 80 irradiated assatblies as described be3Lav, the inplanentatian of a nev CEL configuration (see Section 2.4.2) and the utilization of a "lear leakage" fuel managemnt scheme. This lav leakage fuel management ccnsists of the loading of several came-irradiated B and C assemblies on the core periphery and the izzard loading of most of the fresh Batch D assemblies. This type of lcd leakage fuel management has been successfully employed an other PNR

plants and is eccxxcxrrically attractive since for a specified total energy axtput.

it reduces uranium requirerrents The Cycle 2 1oar3ing will require the renaval of all 73 Batch A asserrblies and 7 Batch B assenblies initially loaded in Cycle 1. These assenblies will be replaced by 24 Batch D asserrblies (3.65 w/o enrichment), -16 Batch W asserrblies (3.65 w/o enrichmnt) carxt~ing 4 burnable poisan shims per asserrbly, and 40 Batch D/ assenblies (3.65 w/o enrichment) ccxxtaining 8 burnable poison shims per assembly. The locations of the poison shims within the lattices for these fresh assenblies as well as the locations of the poison shine for 73 Batch B assenblies, 8 Batch C assenblies, and 16 Batch 0+ assenblies carried aver fran Cycle 1 are sheen in Figures 2.4.1-1 and 2.4.1-2. 'Ihe loading pattern for Cycle 2 is shown in Figure 2.4.1-3.

This loading pattern is applicable for any Cycle 1 exx~int betrtreen 8250 EFPH and 10,000 EH?H. The initial enrichment of each assenbly and the beginning of Cycle 2 assembly burnup distribution for a Cycle 1 length of 10,000 EFPH are presented in Figure 2.4.1-4.

The Cycle 2 core loading pattern is 90 degrees rotationally synxrretric.

That is, if one quadrant of the core were rotated 90 degrees into its neighboring quadrant, each assembly wculd overlay a similar assenbly. This simi]arity includes batch type, nunber of fuel rods, initial enrichment and BOC burnrxp.

Physics characteristics including reactivity coefficients for Cycle 2 are listed in Table 2.4.1-2 along with the corresponding values fnxrr the, "

reference cycle. Please note that the values of pararreters actually eaployed in the safety analyses are different than those displayed in Table 2.4.1-2. The safety analysis parameters were chosen to canservatively bound predicted values with accxrrxnodation far apprcpriate uncertainties and alliances.

2.4.2 CE'A Ccmfi tion, Barik Worths and Shutdown Mar 'n 0 The CEK canfiguration for Cycle 2 differs frcxn that of the reference cycle in that the enrpty part length carxtrol rod drives have had "full-strength" full length cont~1 rods added to them, the banks and subgraups have been reconfigured and a nm lead barik has been installed which consists of 12 "reduced~encjth" Cps each ccxxsisting of 2 B4C fingers and 3 A120 fingres Figure.2.4.2-1 shows the location of all cgas together with hU and subgroup designaticxrs. Figure 2.4.2-2 shaw's the location and orientation of the lead regulating barik (Bank 5) "reduced strength" Cps.

Table 2.4.2-1 presents a surmraxy of CE'A shutdown wort9m and reactivity allcxtrances far the H3C 2 zero pcwer steam line break accident and a ccxrparisan to reference cycle data. The EOC zero poorer steam line break accident was selected. since it is the mast limiting zero paperer transient with respect to reactivity requireaexxts, and, thus, provides the basis for establishing the Technical Specification required shutriawn margin.

Table 2.4.2-2 shows the reactivity worQxs of varicus CEL cjrcxsps calculated at full poorer ~tions for Cycle 2 and the reference cycle.

2.4.3 Power Distribution Figures 2.4.3-1 through 2.4.3-3 'illustrate the all rods out (ARO) planar radial power distributions at BOC2 ~ MOC2, and EOC2 that are characteristic of the high burnup end of the Cycle 1 shutdown window (i.e., 10,000 EFPH).

These planar radial power peaks are characteristic of the ma)or portion of the active core length between abo'ut 20 and 80 percent of the fuel height.

The planar radial power distributions, for the above described region, with CEA Group 5 fully inserted at beginning and end of Cycle 2 are shown in Figures 2.4.3-4 and 2.4.3-5, respectively, for the high burnup end of the Cycle 1 shutdown window.

The radial power distributions described in this section are calculated data without uncertainties or other allowances. However, single rod power peaking values do include the increased peaking that is characteristic of fuel rods adgoining the water holes in the fuel assembly lattice. For both DNB and kw/ft safety and setpoint analyses, in either rodded or unroddedg configurations, the power peaking values actually used are higher than those expected to occur at any time during Cycle 2. These conservative values, which are discussed in Section 3.0 of this document, establish the allowable limits for power peaking to be observed during operation.

Thi range oi allowable axial peaking is defined by the Limiting Conditions for Operation (LCO) of the Axial Shape Index (ASI) . Within these ASI limits, the necessary DNBR and kw/ft margins are maintained for a wide range of possible axial shapes. The maximum three>>dimensional or total peaking factor anticipated in Cycle 2 during normal base load, all rods out operation at full power is 1.93, not including uncertainty allowances and augmentation factors.

The maximum reactivity worths and planar power peaks associated with an Effected CEA event are shown in Table 2.4.4-1 for Cycle 2 and the reference cycle. The Cycle 2 values encompass the worst conditions anticipated during Cycle 2 and are safety analysis values, which are conservative with respect to the best estimate calculated values.

'l, 5

The limiting dropped CEA reactivity worth and maximum increase in radial peaking factor are shown in Table 2.4.5-1 for Cyole 2 and the reference cycle. The values shown for Cycle 2 are the safety analysis values, which are oonservative with respect to the best estimate calculated values.

2.4.6 Scram Reaotivit Scram reactivities as a function of percent insertion are oalculated using the space-time kinetics code FIESTA described in Reference 7. r 2.4.7 Au entation Factors No change from the reference cyole-,safety analysis values.

2.4 8 Anal ical In ut to In Core Measurements In-core deteotor measurement constants to be used in evaluating the reload cycle power distributions will be oalculated in the manner described in References 8 and 9 ~

2.4.9 Uncertainties in Measured Power Distributions The paver distribution measurement uncertainties which apply to Cycle 2 are those described in Reference 8~

2.4.10 Nuclear Desi n Methodolo Nuclear design calculations vere performed using the coarse mesh code ROCS (Reference 9) and the fine mesh code PDQ (Reference 10) ~ All cross sections were generated in accordance with the methods described in Reference 9. All fuel assembly cross sections for both coarse and fine mesh caloulations were. generated using the DIT assembly spectrum codd (Reference 9) vith appropriate corrections to account ior the incr eased peaking that is charaoteristic of fuel pins adJacent to water holes in the assembly lattice. The coarse mesh code ROCS vas used in either 2- or 3-dimensional geometry to calculate all core vide parameters and assembly relative power densities. The fine mesh ".code PDQ in 2-dimensional geometry was used to calculate pin peaking data.

2.5 Thermal H draulic Desi n Steady state DNBR analyses of Cycle 2 at the stretch power level of 2700 Aft have been performed using the TORC computer code described in Reference 11, the CE-1 critical heat flux correlation described in Reference 12, the simplified modeling methods described in Reference 13, and the CETOP code described in Reference 14 '

variation of . TORC called CETOP, optimized for simplified modeling applications, was used in this cycle to develop the "design thermal margin model" described generically in Reference 13. Details of CETOP are discussed in Reference 14. CETOP is used only because it reduces computer costs significantly; no margin gain is expected or credited.

Table 2.5-1 contains a list of pertinent thermal-hydraulic design parameters used for safety analyses and for generating reactor protection, system setpoint information. Using the methodology presented in Reference 15, the caloulational factors (engineering heat flux factor, engineering factor on hot channel heat input and the rod pitch, bowing and clad diameter factor) listed in Table 2.5-1 have been combined statistically with other uncertainty factors at the 95/95 confidence/probability level to define a new design limit of 1.28'n CE-1 minimum DNBR when iterating on power.

2.5.2 Effects of Fuel Rod Bowin on DNBR Mar in Effects of fuel rod bowing on DNBR margin have been incorporated in the safety and setpoint analyses in the same manner as discussed in Reference

16. The value used for this analysis, 1.75$ MDNBR ~ is valid for bundle burnups up to 30,000 MMD/MTU~

For those assemblies with an assembly average burnup in excess of 3'0 GWD/T, the minimum best estimate margin available, relative to more limiting peaking values present in other assemblies, exceeds the corresponding rod bow penalties based. upon Reference 16 ~ Hence, sufficient available margin exists to offset rod bow penalties for assemblies with burnup greater than 30 GWD/To

TABLE 2 ~ 1-1 St. Lucie 2 Cycle 2 Cladding Collapse Predictions Minimum Predicted Batah Time to Colla se (EFPH)>> EOC2 Ex osure (EFPH)

>30 '00 20,000

>30,900 20,000

>29,000 10,000 IEFPH = Effective Full Power Hours

TABLE 2 ~ 1-2 Comparison of Poison Material Content for Full-Length CEAs (5 Elcmcnt)

"Reduced Strcn th" CEAs "Full Stren th" CEAs (Ref. 1)

Poison Material B<C/Ag-In-Cd B<C/Ag-In-Cd (2 Outer Diagonal Elements)

AL203/Inconel 625 (3 Elements, Center and 2 Outer Diagonals)

Poison Length 123/12+5 123/12.5 (inches) 123/13,5

TABLE 2 ¹.1-1 ST. LUCIE UNIT 2 CYCLE 2 CORE LOADING Batoh Average Initial Initial Burnup (MMD/T) 'Poison  : Poison Total Total Assembly Number of Enriohment I EOC1a Rods per Loading Number of Number of'0 Desi nation Assemblies Mtg 0-2 5 000 EFPH) Assembl ( B C/in) Poison Rods Fuel Rods 73 2 28 1¹,700 16 ~ 019 1168 16g060

¹0 2073 8,800 9,¹¹0 C, 2.73 13,800 12 ~ 010 96 1 e 792 16 2.73 12,500 16 ~ 010 256 3i 520 3.65 5,66¹ 16 3. 65 0 ~ 019 3 ~ 712 D/ ¹0 3.65 ~ 019 320 9 ~ 120 Totals 217 190¹ ¹9,308

TABLE 2 4 ~ 1-2 St. Lucie Unit 2 Cycle 2 Nominal Physics Characteristics Reference Cnf te ~Cele ~Cele 2 Dissolved Boron Dissolved Boron content for Criticality, CEAs Mithdrawn Hot Full Power, Equilibrium Xenon, BOC PPM 493 1000 Inverse Boron North Hot Full Power BOC PPM/gap 78 101 Hot Full Power EOC PPM/jgp 76 80 Reactivity Coefficients (CEAs Withdrawn)

Moderator Temperature Coefficients, Hot Full power, Equilibrium Xenon 10 hp/ F <<0 74 W.2 EOC 10 6p/ F -1.76 -2.1 Do ler Coefficient Hot BOC Zero Power .10 5dp/ F -1 ~ 61 -1 ~ 65 Hot BOC Full Power 10 a,/F <<1 e23 -1.32 Hot EOC Full Power 10 5I / F 1 ~ 34 -1 ~ 58 Total Delayed Neutron Fraction defi 0 0073 0 '061 0 0054 0 0051 Neutron Generation Time sac 10 sec 32.2 24.0 EOC 10 sec 33.0 30.0

TABLE 2.4 2-1 St. Lucie Unit 2 Cycle 2 Limiting Values of Reactivity Worths and Allowances for the Hot Zero Power (HZP)

End-of-Cycle (EOC) Steam Line Break (SLB) Accident2 Shp Reference

~Cele ~Cele 2 Worth of all CEA Inserted 9.7 11.5

2. Stuck CEA Allowance '1.6 2.7

3. Worth of All CEA Less Highest 8.1 8.8 Worth CEA Stuck Out Zero Power Insertion 5II 2.0 Limit CEA Bite

5. Calculated Scram Worth >5 6 6.8 (Item 3 minus Item 4)

6. Physics Bias and 0.6 0,9 Uncertainty

7. Net Available Scram Worth 5' 5.9

'(Item 5 minus Item 6)

8. Technical Specification 5.0 5 0%

Shutdown Margin

9. Margin in Excess of Technical >0 OII +0.9 Specification IScram worth assumed in the St. Lucie Unit 2 Cycle 2 HZP EOC SLB transient analysis.

I+Reference Cycle analysis assumed that the PDIL would be specified such that a minimum shutdown margin of 5.0$ hp would be maintained.

l2

TABLE 2 4.2-2 St. Luoie Unit 2 Cycle 2 Reactivity North of CEA Regulating Groups at Full Pmrer, gp Re ulatin CEAs BOC EOC Referenoe Cycle r

Group 6 (Lead Bank) 0.44 0.39 Group 5 0.41 0 45 Group 4 0.97 0.93 Cycle 2 G roup 5 (Lead Bank) 0.70 0.83 Group 4 0.36 0,40 Group 3 0.97 1.05 13

TABLE 2 ~ 4.4 1 St. Lucie Unit 2 Cycle 2 CEA EJection Data Reference Cycle Safety Cycle 2 Safety Anal si s Value Anal sis Value Maximum Radial Power Peak Full Power with the Lead Bank 4 ~0 3.5 Inserted; Worst CEA EJected Zero Power with CEAs Inserted 11.5 7.5 to the ZPPDIL+; Worst CEA EJected Maximum EJected CEA Worth (%ho)

Full Power with the Lead Bank 0.24 0 25 Inserted; Worst CEA EJected Zero Power with CEAs Inserted 0.84 0.60 to the ZPPDIL>>; Worst CEA EJected

<<Zero Power Power Dependent Insertion Limit 14

TABLE 2.¹ 5-1 St. Lucie Unit 2 Cycle 2 Full Length CEA Drop Data (HFP, Equilibrium Xenon)

Reference Cycle Safety Cycle 2 Safety Anal sis Value Anal sis Value Single Drop Minimum Worth ($ hp) 0 0 0 '

Maximum Percent Increase 13 5 14.0 in Radial Peaking Factor (5)

Maximum 15 Minute Xenon 5.1 ¹.0 Redistribution Penalty (5)

Subgroup Drop Minimum Worth (Qp) 0 0 0. 15 Maximum Percent Increase 19.4 19 ~ 0 in Radial Peaking Factor (l) 15

TABLE 2 5-1 St, Lucie Unit 2 Therafal Hydraulic Parameters at Full Power Reference General Characteristics Unit ~Cele 1 ~Cele 2 Total Heat Output (Core Only) HNt, 2560 2700 10 BTC/hr 8737 9215 Fraction of Heat Generated in

'pg 0 975 0.975 Fuel" Rod Primary System Pressure (Nominal) psia 2250 2250 Inlet Temperature (Maximum Indicated) F 548 549 l

Total, Reactor Coolant Flow 370,000 363,000 (Minimum Steady State) 10 ibm/hr 139 ' 136.6 Coolant Flow Through Core 10 ibm/hr 134.3 131 ~ 6 (Minimum)

Hydraulic Diameter (Nominal Channel) ft 0.039 0 039 Average Mass Velocity 10 6 lb/hr-ft 2.45 2.41 Pressure Drop Across Core psi 12,3 11.0 (Minimum Steady State Flow Irreversible Over Entire Fuel Assembly)

Total Pressure Drop Across psi 35.7 34.3 Vessel (Based on Nominal Dimensions and Minimum Steady State Flaw)

Core Average Heat Flux (Accounts for BTU/hr-ft 151,300>> 160,300>>>>

Fraction of Heat Generated in Fuel Rod and Axial Densification Factor)

Total Heat Transfer Area (Accounts 56,315>> 56,060>>>>

Axial'ensification Factor)

Film Coefficient at Average BTU/hr-ft 6200 6100 Conditions oF Average Film Temperature Difference oF 30 ' 30.6 Average Linear Heat Rate of kw/ft 4.43>> 4,70>>>>

Undensified Fuel Rod (Aocounts for Fraotion of Heat Generated in Fuel Rod)

Average Core Enthalpy Rise BTU/lb 65 ~ 1 70 0 1

e Maximum Clad Surface Temperature 657,0 657.1 16

TABLE 2.5-1 (continued)

Reference Calculations Factors ~Cele t ~Cele 2 Engineering Heat Flux Factor 1 030 1 '32+

Engineering factor on Hot Channel 1 030 1 '30+

Heat Input Rod Pitch, Bowing and Clad Diameter F 06 1.05 Factor Fuel Densification Factor (Axial) 1.002 1 002 Notes

+Based on 1632 shims.

+IBased on 1904 shims.

+These factors have been combined statistically with other uncertainty factors at 95/95 confidence/probability level to define a new design limit on CE<<1 minimum DNBR when iterating on power as discussed in Reference 15.

17

4 POISON ROD ASSEttBLY 8 POISON ROD ASSPSLY FUEL ROD LOCATION POI'SON ROD LOCATION FLORIDA POWER 5 LIGHT COe ASSENBLY FUEL AND POISON ROD LOCATIONS, FIGUR St. Lucre.2 4 AND 8 POISON ROD ASSBSLIES 2,4,1-1 Nuclear Power Plant

~

12 POISON ROD ASSEtSLY 16 POISON ROD ASSPIBLY l ~

FUEL ROD LOCATION 5g POISON ROD LOCATION FLORIDA WER 5 LIGHT CO ~ ASSENBLY FUEL AND POISON ROD LOCATIONS, FIGURE Lucre 2 't.

12 AND 16 POISON ROD ASSBSLIES 2.0.1-2 uclear Power Plant

B C D D D/ B C 8 C B D/

C'-.- D/ B D/

C+ B D/ B C D B D/ B C B C B D/ B D/ .C+

B D/ B B C C+ B C+

B D/ B C B D" C+ B FLORIDA POWER 5 LIGHT CO s .ST. LUCIE UNIT 2 CYCLE 2 FIGUR St. Lucre 2 CORE NP 2,0,1-3 Nuclear Power Plant 20

INITIAL ENRICftMENT, w/o IJ-235 2.28 3,65 BOC2 BURNUP (016/T), EOC1 10,000 EFPH 13,300 0 2.73 3.65 3,65 3,65 2.28 8000. 0 0 0 5,600 2,73 3,65 2.2&. '.?3 2.28 3,65'

,500 0 5,400 0,200 5,400 3.65-2.73 3.65 2.73 0',28 3.65 2,28

,500 0 8200 4,900 0 5,300 2?3 2.73 2.73 2.28 3. 65 2,28 2,73 8000 8200 4,900 4,900 0 5,000 0,300 3,65 2,28 3.65 2,28 2.73. 2.28 2,73 2,28 0 5,400 0 4,900 0,300 3,400 7400 4,000 3.65 2.73 2,28 3.65 2,28 3.65 2.73 3,65 2.28 0 0,200 4,900 0 3,400 0 ,700 0 13,300 3,65 2.28 3.65 2.28 2 73: 2.73 2,28 2.73 5.65 0 5,400 0 5,000 7400 ,700 5,600 4,900 0 2.28 3,65 2.28 2,73 2.28 3,65 2,73 2,28 15,600 0 5,300 0,300 4,000, 0 4,900 5,600 FLOR [DA ST, LUCIE UNIT 2 CYCLE 2 OWER 5 L?GHT,COo FIGURE St. Lucke2 ASSEl'tBLY AVERAt)E BURNUP ANQ INITIAl 2.4.1-4 Nuclear Power Plant ENRICOENT DISTRIBUTION 2l

1'-1 5-1 3~2 BQ 5-2 A-1 B-2 2'-2 B-1 BQ 2-2 A-2 4-1 1-2 3'4 84 A-3 2-1 84 B4 A-2 A-1 B-2 4-1 3-2 2-1 4-1 5-1 B-2 B4 B4 84 1-2 3-1 8-1 A-1 A-2 2~2 2'4 2-1 B4 A-2 2-2 A4 BQ 6-2 B4 8-2 A-1 5-2 B4 34 6-1 3-1 B-1 1-2 Y-Z Y ~ CEA BANK DESIGNATION 2 ~ CEA SUBGROUP NUMBER FLORIDA FIGU POWER & I.IGHT CO. ST. LUCIE UNIT 2 CYCLE 2 2.42-1 St. Lucia CEA BANK AND SUBGROUP DESIGNATIONS

'uclear Power Plant

~ 0 0

0 ~

0 0 ~ 0 0

~ 0 o ~

0 ~ ~ 0

~ o 0 ~

0 ~ 0 ~

~ 0 o

~ 0

~ 0 0 ~

0 0 0 ~ ~ 0

~i 0 0 ~

0 0 0 ~ ~ 0

~ 0 0 ~

~ B4C FINGER AI2O3 FINGER FLORIDA Figure OWER & LIGHT COo ST. LUCIE UNIT 2 CYCLE 2 St. Lucfe POSITIONING OF POISON FINGERS IN LEAD BANK 2.42-2 ituc1ear Po~r P1ant 23

0,46 0,92 0.48 0.97 1,23 1.31 0.93 0,54 1.17 0.91 1,06 0,97 1.39 0.54 121 . 1.13 1.38 0.96 1.34 0 QQ 0 43 1.17 1.00 0 91 1.31 0.90 0,95 0,9? 0,92 1.38 0.91 0.95 0.91 1.01 0,87 1.23 1,06 0.97 1.32 0,91 1,25 0.97 1,26 0,4E 1.31 0.97 1,34 0. 90 1.01 0,97 0,74 0.79 0,92 0,93 1,39 0,94 0,95 0.8? 1,26 0,79 0,61 NOTE: X = P!AXINUM 1-PIN PEPK = 1.64 FLOR IDA ST, LUCIE UNIT 2 CYCLE 2 POWER 5 LIGHT COs FIGURE St. Luc)e 2 ASSBSLY RELATIYE POMER DENSITY AT ROC.

2 4.3-1 Nuclear Power Plant EAUILIBRIUN XENON

0,48 0,90 0,49 0.90 1,12 1.28 0,93 0.54 1.11 0.89 1,02 0,98 1.40 0 54 1 14 . I 06. 1.35 0,98 1,37 0,98 0,49 .

1,11 1,07 0.97 0,93 1,35 0,94 0,.99 0,90 0.89 1,36 0,93 0,98 0.96 1,04 0.92 1.12 1.02 0,98 1.36 0.96 1,31 1,01 1,29 0,48 1,28 0.98 1.37 0,94 1.04 1,01 0,31 0,85 0,90 O.93 1.40 0.9e 0.99 0,92 1.29 0.35 0,70 NOTE: X = NAXI%M 1-PIN PEAK = 1.56 FLORIDA ~

ST, LUCIE UNIT 2 CYCLE 2 ER 5 LIGHT COs FIGURE St. Luc)e 2 ASSHSLY RELATI'/E POWER DENSITY AT 5000 EFPH.

Nuclear Power Plant 2.4,3-2 .

EQUILIBRIlN XENON 25

0,51 0.91 0.52 0,90 1,09 1.28 0.95 0,57 1,12 0,89 '1;00 0.98 1,39 0,57 1.13 . 1.05. 1.34 0.99 1.37 0.98 9.52 1.12 1,05 0.97 0,94 1.35 0.95 0,98 0.90 0,39 1.34 0.94 0,98 9.96 1,02 0.91 1.09 1,00 0.99 1.35 0,96 1.31 1.00 1.26 0,51 1,28 0,98 1.36 0,95 1.02 1.00 0.84 0,88 0.91 0,95 1.39 0.98 0.98 0.91 1.26 0,38 0.75 NOTE: X = NXI."lUN 1-PIN PEAK = 1 54 FLORIDA ST. LUCIE UNIT 2 CYCLE 2 POWER Et LIGHT CO ~ FIGUR St. Lucre 2 ASSBSLY RELATIYE t'ONER DENSITY AT EOC, 2.4.3-3 Nuclear Power Plant 'QUILIBRIUM XENON 26

CEA BANK 5 LOCATION 0.46 0,88 0.49 0.98 1.23 1.25 0,88 0.48 1,13 0,96 1,11 0.95 1.02 0,48 0.87 1,11 1.42 1,04 1.35 0,94 X

9.49 1,13 1.11 3.,05 0,98 1,37 0.97 1.02 0,98 0,9? 1.42 0,99 1,01 0.92 1,06 0,95 1,23 1,11 1,37 0,93 0,97 '1,00 1,32 1,25 0,95 1.35 0.97 1.06 1,00 0,81 0,88 0,88 0.88 1.02 0. 94 1,02 0,95 1,32 0.88 0.70 NOTE: X = NXIMUN 1-PIN PEAK = 1.67 FLORlDA ST. LUCIE UNIT 2 CYCLE 2 ER 5 LlGHT COe FIGURE St. t.ucfe 2 ASSBSLY P.EL%TIVE t'ONER DENSITY MITH NucIear Power PIant 2,4,3-4 BANK 5 INSERTED, HFP, BtjC 27

CEA BANK 5 LOCATION 0,54 0,95 0.97 1,16 ,130 0.92 1.13 0 95 1.06 0,96 1.02 0,51 0,81 1,02 1 42 1,04 1.39 0,95 0,55 1,13 1,02 0.99 0.98 1,41 0.93 1.01 0,97 0.95 1,42 0. 99 1,00 0.93 1,02 0,93 1.16 1.06 1,04 1,42 0.93 0.94 0,95 1.26 0.54 1.30 0,96 1,39 0.98 1.02 0.95 0.82 0,89 0,95 0,92 1.02 0,95 0,93 1,26 O,S9 0,77 NOTE: X = NXINUN 1-PIN PEAK = 1.53 FLORIDA ~

ST. LUCIE UNIT 2 CYCLE 2 POWER 5 LIGHT CO< FIGUR St. Lucre 2 ASSENBI Y RELATIYE PONER DENSITY MITH Nuclear Power Plant 2.4,3-5 BANK 5 INSERTED, HFP, EOC 28

3 0 POMER CAPhBILITY LND DESIGN BhSIS EVENT EVhLUhTION 29

3.! ~lid 1!

evaluation of power capebility wes performed for Cycle 2 reletive to An Cycle 1 ~ 'his evaluation identified the major margin loss and gain mechanisms for Cycle 2 that influence the Technical ~cificetion limits.

For the ex-core Linear Heat Hate (IHR) Limiting Conditions for Operation (ICO) and Limiting Safety. System Setpoint (L";S .), the major narpin loss mechanism for Cycle 2 is increased per>in@. This loss is .offset by giins due to Statistical Combination of Uncertainties. Por the Departure Iran Nucleate 2oiling (DlS) ICO and LSSS, the major margin loss mechanis..s for Cycle 2 are increased peeking, and reduced PCS echnicel Speci ication flow. These losses ere primarily offse+ by gains due to Statist c~2 Combination of Uncertainties. A minor @~begin loss mechanism is increased EBS inlet temperature. Pinor margin gain mechanisms are improved F. guire9 Overpower fhrgin (Hei) results, improvements in the exiel power distributions, and use of a statistically based thermal-hydraulic model.

Por th IHH-LS"-.";, the m".jor margin loss is epproximetely:

1. c,. es a result of increasing the Technical pecificatinr.

from 1.60 to 1.75.

The margin ga,in fr the LPR-LSSS due to "tatistical Combination o Uncertainties is about 5+. Cycle 1 design ealso had significant excess Ave ileble Overpower )hain (AOP~i), greater then 9. 5~z, whi ch eries conservative operation during Cycle 2 at the previous LP.-ISSS limit.

Por .he ex-core IEB-LCO, +he major margin loss is approximately:

~ ~

1. o, as a result of ircreasing +he Technical pecif ice+ion from 1.60 to 1.75.

The margin gran for the ex-core M-ICC due to Statistical Combiration o Uncertainties is about 6+. h1inor sources of margin gain, such as the somewhat less adverse axial power distributions of r load co. es end the use excess margin of the Cycle 1 desig., account for a margin g in of about 2-.~. The net margin loss, of epproxinately 5~, is of set by redu ing the maximum allowed power (with ex-core monitoring only) frm 92.5... to 99" of rated power end shifting the maximm allowed power Axial crepe ~~ dex (A". )

limit from .15 asiu to -.10 asiu.

30

For the D~LSSS, the major margin losses are approximately:

1. P~ as a result of increasing the Technical ~Q~ification F- and P~ from 1.60 to 1.70 and 1.60 to 1.75, respectively.

2. F~ as a result of reducing the Technical Specification minim nn flow

~.

RC fran 370,KD gpm to 63,KO The margin gain for the DHB-LSSS due to Statistical Combination of Uncertainties is approximately 14~'argin gains from less adverse axial power distributions and using a statistically based thecal hydraulic zo".el total about 2. ~ Additional operational margin was gained through optimization of the 24/LP trip setpoints.

For the DIG-ICG, the major margin losses are approximately:

1. P'sfrcraa resu' of increasing the Technical pecificeti on Fand F~ 1.60 to 1.7C and 1.60 to 1.'75, respectively.

2. 2. as a result of reducing the RCS Technical Sp cificetion flow fran

~Q,OCO gpm to 363,000 gpn.

%e margin gain due to the Statistical Gmbina+ion of Uncer.ainties is approximately 12~. Margin gains of about 4+ result from minor sources including less severe axial power distribu+ions, use of a sto+istical~~

base thermal-hydraulic model, and a reduced Required Cverpower M rgin (HOPi) for V~ sub-group dropSR.considerations alone wou~d permit the D.'8-ICO to be identical to Cycle 1. however, small brea'c IG"A reguir~ents reouire thet the fu" 1 pow r PZI be no more neg tive then .OD axis]

units (asiu) (after application of uncertainties). shape'ndex 31

3,2 KOZ-IKA HPZEI7. AItALY S 3.2.0 In.roduction This section presents the results o the Florida Power end Lij.+, "+- Lucie Unit, 2, Cycle 2 Ron-LOCA safety analyses.

The Design Bases ver.ts (DBIh) considered in the safety an"~yses are "istec <<n Table 3.2.0-1 ~ These events are categorized into .wo groups: I<<oderate Frequency events (re erred to herein as An icipated Operational Occurr~wces,

~

AOOs) and Postulated Accidents. The DZEs were evaluated with respect to four ~

criter'a: Offsite Dose, Reactor Coolant Pystem Pressure,. Peel Perform.;n e and Loss of Shutdown Nargin. Tables 3.2.0-2 through 3.2.0-5 present the list of events analyzed for each criterion. All events were reanalyzed or re~value~ed to assure that they meet their respective criterion. he D~ chosen for ana2ysis for each 'ri+erion ere the lir.itinG event., with respect to +ha .

criterion. The CVCS Nalfunction event (Section 3.2.5.1) v~ analyzed to ensure ttmt the operator has suf icient time to terminate the event before +he pressurizer fills solid.

3.2.0.1 I".ethods of An~" sis Table .2.~~2 presents the events which were an~~ zed with r ..pect to the o fsite dose criterion., The methodology used is consistent with Cycle 1 an~lysis m +hods (Peference 17}. For those cases. where reported doses include pre-existing and/or accident generated iodine spil:ing, analyses methods are consistant'eath those of Reference.1.

AGE are ar~Dyzed to assure that "pecified Acceptable Fuel Design Iimi+s on Departure frcrn nucleate Boiling (D"2) and fidel Centerline to Pelt 'SAFDLs)

(CiK) limits ere not exceeded. The methodology used by Combustion m~ginecring integrates Transient analysis results. with the calculation of Limiting S fety ystem Set tin~ (L SS) ar." Limiting 'Conditions for Operation (ICO ) . h.'s

~

methodology is described in Reference 2. AOOs are divided into two categories

( ale 3.2.0-<):

1 ~ Design >~sis Zvents Pequiring EP. trips to assure tha+ SAH)Xs are not exceeded

2. Design Basis Events f'r which RPH trips and/or ufficient Initial Steady State Margin (preserved by the ICOs) are necessary to prevent exceeding the SAFDle.

Transient analysis for the first category determine the values of par~~eters used as input to the ~~ calculation (e.g., the pressure bias and the transient power decalibration term are calculated f'r DBM in this catepo~ and the limi+ing values of these parameters are used as input to the hermal Nw~n/Low Pressure (5N/LP) trip .nJculator).

Transient analysis for DBEs in the second category determine the values o parameters us d as input to the L~SS and/or ICG calcu2ations (e.g., Recuired Overpcwer I<argin (ROB!) ).

32

ransient analysis of the events in the latter category were performed utilizing the Statistical Combineti on of Uncertainties (SCU) methodology (Appendix 1 of this document and Reference 3).

3e2.0.2 Ywthmsti cal Nodels Plant response for lion-LCCA Events was simulated using the CZSZC computer code (Section 15e0.4-1.1, Appendix 15D of Reference 17). The S RH<2l II computer code (Section 15.0.4.1.2 of Reference 17 and Reference 4) was also used in the analyses of the Loss of Flow Event and the CEA E)ection Event.

Simulation of the fluid conditions within the ho+ chanel of the reac+or core and prediction of DNB was performed using the CEZQP-D computer code (Sec+ion 2.5.1 of this report and References 5 and 6).

Determination of IBGR for the post trip return to power por+ion of the stea, iping failure events are based on the correlation developed by R. P.. I'eth Reference 9). Corrections developed by Lee (Reference 10) are employed in order to use the Y+Eeth correle+ion (for rod bundles) to predict burrout es a function of,axial height, accounting for non-uniform axial heat flux. This methodolody is corsietent with that. employed in the Cycle 1 analysis (Refer~roe 17).

3.2.0.3 In . t Parameters and Anal sis As +ions Table 3.2.0-6 presents the key parameters assumed in the Cycle 2 +ransient analysis and compares them to the values used in Cycle 1. Specific initial conditions for each event are tabulated in that'vent's section. Kost events reanalyzed to determine the effect of changes to keey parameters. 'ere Significant input changes from Cycle 1 to Cycle 2 include an increase in rated core power, increases in rsdial peaks and a lower assumed Technical Specification minimum allowed va'ue for reactor coolant flow.

Table .2.0-7 presents the Reactor Protection @stems (RPS) and Engineering Sa ety Features Actuation System (EPAS) Instrumentation analysis trip setpoints and delay times. In most cases, the values in the table include uncert"inties which are intended to be larger than those calculated.

Table 3.2.0-8 presents the key parameters assumed for the dose calcu'ations.

33

TABLE320 1 STo LUCIE UNIT 2y DESIGN BASIS EVENTS CONSIDERED ZN THE CYCLE 2 SAFETY ANALYSIS 3.2.1 Increase fn Heat Removal by the Seoondary System 3o2o1 ~ 1 Decrease fn Feedwater Temperature 3o2o1o2 Increase fn Feedwater Flow 3o2r1o3 Increased Main Steam Flow 3 2 1.4 inadvertent Opening of a Steam Generator Safety Valve or Atmospheric Dump Valve 3.2.1.5>> Steam System Piping Failures 5.2.1.5a Inside Containment Pre-Trip Power Excursians 3.2.1.5b Outside Contafnment Pr e-Tr ip Power Excursians 3.2.1.5o Post-Trip Analysis 3o2o2 Deer ease in Hest Removal by the Secondary System 3,2,2 1 Loss of External Load:

3r2o2o2 Turbine Trip Loss of Condenser Vacuum 3o2o2o3 322.4 Less ef Normal AC Power 3,2,2 5 Loss of Normal Feedwater 3o2o2.6>> Feedwater System Pipe Breaks 3o20 3 Decrease in Reactor Coolant Flowrate 3o2o3 ~ 1 Partial Loss of Forced Reaetar Coolant Flow 3020302 Tatal Loss af Farced Reactot Coolant Flow 3233 Single Reaetar Coolant Pump Shaft Seixur e/Shear ed Shaft 3 2,4 Reactivity and Power Distribution Anomalies 3.2.4.1 Uncontrolled CEA Nthdrawal fram a Subcritical or Law Fewer Conditian 3.2.4.2 Uncontrolled CEL Mfthdraws1 at Power 3.2.4 3 CEA Drop 3.2.4.4 CVCS Malfunction (Inadvertent Boron Dilution) 3.2.4.5 Startup of an Inactive Reactor Coalant System Pump 3.2.4.6>> ContraL Element Assembly E5eetion 3 2.5 Increase fn Reactor Coalant System Inventory 3 2,F 1 CVCS Malfunction 3 2o5.2 Inadvertent Operation of the ECCS During Power Operation 34

TABLE 3.2.0-1 (continued) 3.2.6 Decrease in Reactor Coolant System Inventory 3.2.6.1 Pressurizer Pressure Decrease Events 3.2.6.2>> Small Primary Line Break Outside Containment 3.2.6.3>> Steam Generator Tube Rupture 3.2.7 Miscellaneous 3.2.7.1 Asymmetric Steam Generator Events Postulated accidents 35

ThBLE 3e2.0&

DBEs hNALYZED WITH RESPECT TO OFFSITE DOSE CRITERION Event Sentinn h) hntioipated Operational Ooourrenoes

1) Inadvertent Opening of a Steam Generator 3.2.1.4 htmospherio Dump Valve or Safety Valve

2) Loss of Normal hC Fewer 3.2.2.4 B) Postulated hooidents

1) Steam System Piping Failures; 3.2.1.5a Steam Line Break Event Outside Containment Pre-Trip Pcwer Excursions

2) Feedvater System Pipe Breaks 3.2.2.6

3) Single Reaotor Coolant Pump Shaft Seizure 3e2e3 e3

4) Small Primary Line Break Outside Containment 3.2.,6.2

5) Steam Generator Tube Rupture 3.2.6 '

36

4 TABLE 3,2,0 3

DBEs ANALYZED lARITH RESPECT TO RCS PRESSURE CRITERION I e

... Event Section

-'. A) Anticipated Operational Occurrences

1) Loss ot Condenser Vacuum 3 02 02 e3 I

2) Loss of Normal AC Power 3.2.2.¹

3) Uncontrolled CEA Mithdrawal at Power 3,2,¹,2 J-

B) Postulated Accidents

1) Feedwater System Pipe Breaks 3.2 2.6 e

37

TABLE 3 2,0&'BEs ANALYZED MITH RESPECT TO FUEL PERFORMANCE EVVllt Stattan A) Antioipated Operational Occurrences Requiring RPS Trip to Assure that the SAFDLs are not Exoeeded

1) Deorease in Feedwater Temperature 3o2el ~1

2) Inorease in Feedwater Flow 3o2 ~ 1t2

3) Inoreased Main Steam Flow 3+2o1 t3

4) Uncontrolled CEA withdrawal from a 324 ~1 Subcritical or Low Power Condition

5) Uncontrolled CEA Mithdrawal at Power 3,2,4t2

6) Pressurixer Pressure Decrease Events 3.2.6.1 B) Anticipated Operation Occurranoes for which RPS Trips and/or Sufficient Steady State Margin (LCO) are Necessary to Prevent Exceeding the SAFDLs

1) Total Loss of Foroed Reaotor Coolant Flow 3020302

2) CEA Drop 3,2 4~3

3) Asymmetric Steam Generator Events 3o2o7 F1 C) Postulated Accidents Steam System Piping Failures;

1) Inside Containment Pre-Trip Power Excursions 3.2.1.5a N

2) Outside Containment Pre-Trip Power 3+2 ~ 1.5b Excursions

3) Post Trip Analysis 3.2.1.5c

4) Single Reaotor Coolant Pump Shaft Seixure 3020313

5) Control Element Assembly E)ection 3.2.4 ~ 6 38

'I I'

.ar II 4

~ ~

I*

a r

'TABLE 3.2,0%

3 DBEs ANALYZED WITH RESPECT TO SHUTDOWN MARGIN'RITERION

, Eaaeht  :." Siat than r

A) Anticipated Operational Occurrences ~

I 3

1)a Inadvertent Opening of'a Steam Generator Safety Valve or Atmospherio Dump Valve =3;2.1.4--

2) CVCS Malfunction (Inadvertent Boron Dilution),.;

aa

8) Postulated Accidents t)e Steam System Piping Failure, Post Trip 3."2.t.5e

'nalysis 3-These events were considered to ensure reliable control .oi reactiv,ity-following trip.

ra I

aa

~ ~

a ir r

al r

r I'

I' r

II k a.

h a' Ia r

ar raa 39 a

TABLE 3,2.0%

ST LUCIE 2 UNIT 2 CYCLE 2 CORE PARAMETERS INPUT TO SAFETY ANALYSES Reference Cycle Values Safet Parameters Units (C cle 1) C cle 2 Values Total RCS Power 2630 2720a~ 2774 ~

(Core Thermal Power

+ Pump Heat)

Maximum Steady State 551 549+a 552 Temperature Minimum Steady State psia 2200 2225+~ 2172 RCS Pressure Rated Reactor 370,000 377,500, 363;000 Coolant Flow Negative Axial Shape ~3 -o25 LCO Extr'erne Assumed at Full Power (Ex-Cores)

Maximum CEA at Full Maximum Insertion Power Initial Linear of Lead KM/ft Bank'5 Insertion 28 13 0 13 0 Heat Rate for Transient Steady State Linear KM/f t 21 0 22 0 Heat Rate for Fuel CTM Assumed in the Safety Analysis CEA Drop Time from 3 ~0 2.7 Removal of Power to Holding Coils to 90$

Insertion Minimum DNBR CE 1 1.20 1.28++

MoBeth 1 +30 1 30 For events under category B of Table 3.2.0-4, the effects of uncertainites on these parameters were accounted for statistically (see Appendix I).

Therefore, these values do not include uncertainties.

Cycle 2 value for MDNBR based on the CE-1 condition is the result of the statistioal oombination of uncertainty program which oause the MDNBR values to inorease (see Appendix I) ~

40

TABLE 3.2.0-6 (continued)

Reference Cycle Values Safet Parameters Units (C cle 1) C cle 2 Values Radial Peaking Factors For DNB Margin Analyses (F )

Unrodded Region 1.60 1,70, Bank 5 Inserted to 1 7 1o74 PDIL Limit at 100$ Power For Panar Radial Coanonent (F ) oi 3-D Peak (CS Limit Analyses)

Unrodded Region 1.60 1.75 Lead Bank Inserted to 1.75 1 e91 PDIL Limit at 100$ Power Maximum Augmentation 1.055 1o055 Factor Moderator Temperature 10 ~>/oF -2.7 to +.5 -2.7 to +o5 Coefficient (below 70$ power)

-2.7 to OoO (70$ power and above)

Shutdown Margin (Value  %,0 Assumed in Limiting EOC Zero Power SLB) 41

TABLE 3e2o0-7 RPS AND ESFAS TRIP'SETPOINTS AND DELAY TIMES ASSUMED IN SAFETY ANALYSIS Technioal Specifioation Analysis Total Delay RPS Tri Function Value ~Set oint Time (sec)

Variable Power Level - High 10 10 0 g(1)

($ Above Initial Power Level)

Variable Power Level - Ceiling 107 109 105 0 g(1)

.($ Rated Thermal Power)

Variable Power Level - Floor 15 17(4)

(S Rated Thermal Power)

Pressurizer Pressure - High 2370 2028, 2065 1 ~ 15 Psia Pressurizer Pressure - Low 1900 1820(6) 1785(5) 0 9(1)

(Floor of Thermal Margin/

Low Pressure), Psia Steam Generator Pressure - Low 626 557, 500(5),510(7) 1.15 Psia Steam Generator Pressure - High 120 222 1,15 Difference, Paid Steam Generator. Level - Low 39.5 5 0 1 ~ 15

$ Narrow Range Tap Span Reactor Coolant Flow - Low 93.0, 70.0(5) 0 65

$ of Rated Flow Containment Pressure - High 4.0 4.65 1.55 Psig 42

TABLE 3.2.0-7 (contfnued)

Technical Specificatian Analysis Total Delay

~ ESFAS Function Value ~Sat oint Time (sec)

Safety In)ectfon 1736 1608, 1578 30+0 Actuation Signal (SIAS) on Pressurizer Pressure - Low, Psfa Main Steam Line Isolation 600 460(5) 6.75 Sfgnal (MSIS) on Steam Generator Pressure - Low Psia Main Feedwater Isolation on 600 <<0'(5) 5.15 Steam Generator Pressure - Low, Psia When credit is taken far AT Power Calculator portion of the trfp, Resistance Temperature Detector (RTD) response time of 8.00 seconds are explicitly modelled.

(2) Credit for the ceiling af variable high power trip was taken anly for the Stcam Line Break Event (pre-trip power peaks). 'ther events which took credit for a variable high power trip oonscrvativcly used a setpoint of 112$ of rated power (10% above initial power of 102%).

2'5 uncertainty was taken fn negative direction fn Steam Line Break Event (post-trip paver peaks) since cooldown (see Section 3.2.1.5c).

it will result in more adverse Additfonal uncertainties were added to this value for conservatism for the CEA Education Event initiated from Hot Zero Power.

(5) Values include harsh environment uncertainties (for Inside Containmcnt Steam Line Break and Feedlinc Break Events)

(6) Pressurfze Pressure Decreasing Events (Section 3.2.6.1) used an analysis setpaint of 1799 psi which is conservative with respect to thfs value.

(7) conservatively low analysis setpofnt used fn Hot Zero A Power post trip steam line break event (Section 3.2.1.5c) 43

'TABLE 3+2 OA PARAMETERS 'USED IN CALCULATING SITE BOUNDARY DOSE Paraaetsr Units Value Primary to Secondary Leak Rate 1,0 4

Reaotor Coalant System Maximum uCi/gm 1 0 Alliable Concentration (DEQ I-131)

Reactor Coolant System Maximum uCi/gm 60 '

Concentration for Pr~xisting Iodine Condition (PIS) koeident Generated Iodine Spiking 500 Factor

'00/E Reactor Coolant System Maximum Ci/gm Alliable Concentration of Nable Gases Steam Generator Maximum Allowable u Ci/gm 0~1

,Concentration (DEQ I-131)

Partition Factor:

ktmospher io Dump Value 1 0 Condenser Air Educators ~ 01 Main Steam Safety Valves 1 ~0 Mater Stcam Phase Partition .01 Atmospheric Dispersion Coefficient sec/m3 Exclusion Area Boundary (EAB) t,60xt0 Los Population Zone 7.txtO~

Breathing Rate m3/sec 3 47xt0 Dose Canversion Factor Rem/Ci 1.48xt0 44

3 2~1 INCREASE IN 'HEAT REMOVAL BY THE SECONDARY SYSTEM 3 2.1 ~ 1 DECREASE IN FEEDMATER TEMPERATURE 3.2 ~ 1.1.1 Identification af'auses The Decrease in Feedwater Temperature Event is analyzed to ensure that the Departure from Nucleate Boiling (DNB) and Fuel Centerline to Melt (CTM)

Speoified Acceptable Fuel Design Limits (SAFDLs) are not violated.

A decrease in fcedvater temperature may be oaused by!

A. k lass of one of several feedvater heaters. The loss could be due to interruption of steam extraction flow or to an accidental a'pening af a feedvater heater bypass line. The high gressure heaters increase. the feedwater temperature by approximately 60 F. In order to lese this heating, tva valves (one per extraction line) vould have to close. The loss of any of the lav pressure heaters before the feedvater pumps vill produce a lesser effect due to the compensating effect of the high pressure heaters in the eyole.

B. Acoidcntal starting of the kuxiliary Feedvater System. The Auxiliary Feedwater'ystem supplies relatively cold water from the condensate storage tank to the steam generators; an accidental starting of this system vould, therefore, simultaneously decrease feedvater temperature and increase feedwatcr f'lov. Since the maximum capacity of'n auxiliary feedwater pump is about 3 percent of nominal full power f'lav, this accident has a smaller effect on the reactor than the other accidents discussed in this section, and Section 3.2.1.2 (increase in fecdvater flow).

Protection against these undesirable conditions is provided by the Variable High Fewer Level Trip. kdditianal proteetian is provided by other trip signals including High Rate of Change of Pover and Lov Steam Generator Pressure. In this analysis, credit is taken anly for the action af the Variable High Power Trip in the determination oi the minimum transient Departure from Nucleate Boiling Ratio (DNBR) and the maximum approach to the Centerline to Melt (CTM) limit.

As an extreme example of a decrease in fccdwatcr temperature, an accidental, instantaneous dccrcase ofeedvater temperature by 100 F has been analyzed.

3.2 ~ 1 ~ ~.2 Anal sis oi Effects and Cense cnces The Decrease in Feedwater Temperature Event was initiated at the conditions givgn in Table 3.2.1.1-1. A moderator temperature coefficient (MTC) of -2.7 x 10 kp / F vas assumed in the analysis. This MTC, in, conjunction with the decreasing coalant inlet temperature, enhances the rate of increase in the core heat, flux at the time of reactor trip. A minimum fuel temperature caeffioient (FTC) ~ corresponding to beginning af'ycle conditions vith an uncertainty,of 15%, was used in the analysis since this FTC results in the least amount of negative reactivity additian ta mitigate thc transient increase in core heat flux. The minimum CEA worth assumed to be available for shutdown at t;he time of reactor trip far full power operation is -5%kp ~ The pressurizer prcssure control system vas assumed to be inoperable because this minimized the RCS as

pressure durfng the'vent and therefore reduced the calculated DNBR. ilI, other control systems vere assumed to be fn'anual mode of operation and have no, aignificant impact on the results for this event.

3.2,t;t.3 Results The Decrease in Feedvater Temperature Event resulted in a Variable High Poser Trip at 21.2 seconds. The minimum DNBR oalculated for the event fnftfated at the oondftfons specified in Table 3.2.1.1-1 was 1.34 compared to the design limit of'.28. The maximum local linear heat generation rate for the event was 15.2 KV/ft oompared to a design limit of 22 KV/ft.

Table 3.2.1.1& presents the sequence of events for the Decrease in Feedvater Temperature Event. Figures 3.2.1.1-1 to 3.2.1.1-5 shoe the NSSS response for pcwer, heat flux, RCS temperature, RCS pressure and steam generator pressure.

For radiologfoal release accessment and potential for loss of shutdown margfn, >

an inadvertent opening of a secondary safety valve envelopes the events above.

h presentation of the Inadvertent Opening of a Steam Generator Safety Valve or Atmospheric Dump Valve Event fs contained fn Section 3.2.1.4.

3.2.1.1.4 Conclusions For the Decrease in Feedvater Temperature Event, the DNBR and CTM limits are not exoeeded. In addition, the reaotivfty transient during a Decrease in Feedvater Temperature Event fs less limiting than the Inadvertent Opening of s Steam Generator Safety Valve or ktmospher fc Dump Valve Event presented in

'ections 3.2.1.4.

The radiological oonsequences of the event are enveloped by those presented fn Section 3.2 '.4 (Inadvertent Opening of a Steam Generator Safety Valve or htmospheric Dump Valve Event) ~

46

TABLE 3,2,1 ~ 1-1 KEY PARAMETERS ASSUMED FOR THE DECREASE IN FEEDWATER TEMPERATURE EVENT Par ameter Units Vslns r

Total RCS Power 2774 (Core Thermal Power +

Pump Heat)

Initial Core Coolant Inlet 552 Temperature Initial Reactor Coolant System psia 2180 Pressure Initial RCS Vessel Flow Rate 363,000 Moderator Temperature Coefficient x10 ho/ F ~2s7 CEA Worth at Trip Doppler Coefficient Multiplier .85

TABLE 302.1 ~ 1-2 SE UENCE OF EVENTS FOR THE DECREASE IN FEHNATER TEMPERATURE Time (sec) Event Set int or Value 000 Failure of High Pressure Feedwater Heaters 21,2 Variable High Power Trip 1 $ 25 Signal Generated 21.6 Trip Breakers Open 21 ~ 95 CEAs Begin to Drop in the Core

22. 1 Maximum Power Generated 116.4S Maximum Linear Heat Generation 1502 KW/ft Rate 22.3 Minimum DNBR Reaohed 1 34

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53

'3+2 ' 2 INCREASE IN FEEDWATER FLOW

'3.2,1.2.1 Identification of Causes The Increase in Feedwater Flow Event is analyzed to ensure that the Departure from Nucleate Boiling (DNB) and Fuel Centerline to Melt (CTM) Speci fied Acceptable Fuel Design Limits (SAFDLs) are not violated.

An inorease in feedwater flow may be oaused by increasing the opening of a feedwater control valve or accidental starting of the Auxiliary Feedwater System. Complete opening of one feedwater control valve can increase feedwater flow by about 20 percent above nominal, while an aocidental starting of an auxiliary feedwater pump increases flow by about 3 percent above nominal.

Excessive feedwater flow may result in a lower temperature in the reactor ooolant system, higher reactor power due to the moderator feedback assooiated with a negative moderator temperature coefficient and high water levels in the steam generators. Protection against these undesirable conditions is provided <

by. steam generator water level alarms with automatio or manual control actions to reduoe feedwater flow and in extreme cases by reaotor trips due to high power, low pressurizer pressure, thermal margin/low pressure, or low steam generator pressure. As an extreme example of an increase in feedwater flow, an event simulating instantaneous, complete opening of both feedwater control valves has been analyzed. This event repres'ents the worst increased feedwater flow event (the opening of one feedwater control valve) with the worst single

. failure (the simultaneous opening of the other feedwater control valve).

3.2.1.2.2 Anal sis of Effects and Conse ences The inorease in feedwater flow event was initiated at the oonditions Qven in Table 3.2.1.2-1. A moderator temperature coefficient (MTC) of -2.7 x 10 g>g F was assumed in the analysis. This MTC, in conJunction with the decreasing coolant inlet temperature, enhances the rate of increase in the oore heat flux at the time of reactor trip. A minimum fuel temperature coefficient (FTC),

corresponding to beginning of cycle conditions with an uncertainty of 15$ , was used in the analysis 'since this FTC results in the least amount of negative reactivity addition to mitigate the transient increase in core heat flux. The minimum CEA worth assumed to be available for shutdown at the time of reactor-trip for full power operation is -5$ hp . The pressurizer pressure control system was assumed to be inoperable beoause this minimized the RCS pressure during the event and therefore reduced the oalculated DNBR. All other control systems were assumed to be in manual mode of operation and have no significant impaot on the results for this event.

3,2. 1,2.3 Results The Inorease in Feedwater Flow Event was assumed to result from an instantaneous failure to the full open position of both feedwater contr ol valves, which increased the main ieedwater supplied to the steam generators end led to increased heat extraction from the primary ooolant. The event had the same effect on the primary system as a small increase in turbine demand which was not initially matched by an increase in oore power. The RCS reached a new equilibr ium with lower primary pressure and primary ooolant temperatures, higher oore power, and a DNBR which was lower than the initial steady-state

DNBR value. A new equilibt isa was also established in the secondary system with lower temperatures and pressure. Ln equilibrian core power of 104.6$ was reached at approximately 35 seconds. The minim+a DNBR calculated for the event initiated fran. the conditions specified in Table 3.2.1.2-1 was 1.63 ccepared to the design limit of 1.28. Ihe'maximum local heat generation rate for the event was 13.6 KM/ft, compared to a design limit of'2 KM/ft.

The sequence of events for the Increase in Feedwater Flow Event is presented in Table 3.2.1.2-2. Figures 3.2.1.2-1 to 3.2.1.2-5 show the NSSS response for core power, core heat flux, RCS temperature, RCS pressure and steam generator pressure.

For radiological release assessment snd potential for loss of shutdown margin, an inadvertent opening of a secondary safety valve envelopes the events above.

A presentation of the Inadvertent Opening of a Steam Generator Safety Valve or Atmospheric Dump Valve Event is contained in Section 3.2.1.4.

3.2. 1.2. 4 Conclusions For the Increase in Feedwater .Flow Event initated by the simultaneous opening of both feedwater control valves, the DNBR and CTH limits are not exceeded. In addition, the reactivity transient during the event is less limiting than the corresponding inadvertent opening of a secondary safety valve pr esented in Section 3.2.1.4.

The radiological consequences are bounded by those presented in Section 3.2.1.4 (Inadvertent Opening of a Steam Genet ator Safety Valve or Atmospheric Dump Valve) .

TNLE 3.2e1e2-1 KEY PARAMETERS ASSUMED FOR THE INCREASE IN FEEDWATER FLOW EVENT Parameter Units Value Total RCS Pmrer (Core Thermal Poser +

Pump Heat)

Initial Core Coolant OF 552 Inlet Temperature Initial Reactor Coolant System psia 2180 Pressure

'I Initial RCS Vessel Flcnr Rate Ipm 363 F000 Moderator Temperature Coefficient x10 hp/ F ~2e7 CEA Worth at Trip Shp W 0 Doppler Coefficient Multiplier ~ 85 56

TABLE 3 2 1 2M S UENCE OF EVENTS FOR THE INCREASE IN FEEMATER FLOV Time (deo) Event Set int or Value 000 Feedwater Control Valves Fully Open 35.0 Core Power and Core Heat 100 ~ 6$

Flux Beaoh New Equilibrium Maximum Linear Heat Generation 13 ~ 6 lS/ft Bate '

P Minimum DNBR 1.63 57

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3.2 1 3 INCREASED MAIN STEAM FLOM 3.2.1.3.1 Identf fieatfon af Causes The Increased Main Steam Flow'vent is analyzed to ensure that the Departure fram Nucleate Boiling (DNB) and Fuel Centerline to Melt (CTM) Specified Acceptable Fuel Desfgn Limits (SAFDLs) are not violated.

Increased Main Steam Flow Event is defined as any rapid fncrease in steam I'n generator steam flaw other than a steam lfne rupture (dfscussed fn Section 3.2.1.5) or an inadvertent opening of a secondary safety value'discussed in Section 3.2.1.0) ~ Such rapf d increases in steam flow result fn a power mismatch between core power and steam generator load demand. Consequently, there is a decrease in reaotor coolant temperature and pressure. In the presence of a negative moderator temperature coeffioient of reactivity, the decl ease fn reactor coolant temperature oauses an increase in core power.

The Hfgh Power Level and Thermal Margin/Law Pressure (TM/LP) trfps provide primary protection to prevent exceeding the DNB limit during this event.

Additional protection is pr ovided by other trip signals including Low Steam Generator Mater Level and Low Steam Generator Pressure. The approach to the CTM limit is terminated by either the DNB related trip or the High Power Level Trip. In this analysis, credit is taken only for the action of the Variable High Power Level Trip in the determinatian af the minimum transient DNBR and maximum local linear heat generation rate.

The following increased msfn steam flaw incidents have been examined:

Opening of the turbine control valves at Hot Full Power (HFP) due to controller failure.

Opening of the turbine control valves at hat standby due to controller failure. The most rapid load fncrease st hot standby would aecur for the ease in which ft fs assumed that the turbfne control valves opened completely.

Opening af a single valve within either thc Steam Dump and Bypass System, ar the Atmospheric Dump System.

3.2.1.3.2 Anal sis af Effects and Cense enccs The opening of the turbine control valve at full power was initiated at the conditions in Table 3.2.1.3-1. h moderator temperature coefficient (MTC) of -2.7 x gian10 Ap / F was assumed in the analysis. This MTC, fn con)unction with the decreasing coolant inlet temperature, enhances the rate af increase fn the core heat flux at the time of reactor trip. A mfnhnun fuel temperature coefficient (FTC), corresponding to beginning of cycle condf tions with an unoertainty of 15$ was used in the analysis sfnce this FTC results in the

~

least amount of negative reactivity addition to mitigate the transient increase in core heat flux. The minimum CEA worth assumed to be available for shutdown at the time of reactor trip for full power operatian is -5$ hp. The pressurizer pressure control system was assumed to"be inoperable because this minimized the 63

e

~

/

RCS pressure during the event and therefore reduced the oalculated DNBR. All other control systems were assumed to be in manual mode of operation and have no significant impact on the results for this event.

f The FSAR analysis (Reference 7) concluded that the opening of the turbine control valves at xero power and the opening of a single steam dump and bypass valve or an atmosphere dump valve produces less severe results than opening of the turbine admission valves at HFP. Reanalyses confirm that conclusion.

3. 2. 1. 3. 3 Results

'The Increased Hain Steam Flow Event resulted in a High Power Level Trip at 20.3 seconds. The minimum DNBR calculated for the event initiated from the conditions speoified in Table 3.2.1.3-'1 was 1.34 compared to the. design limit of 1.28. The maximum local linear heat generation rate for the event was 15.2 KM/ft, compared to a design limit of 22 KM/ft.

Table 3.2.1.3-2 presents thc sequence of events f'r the event initiated at HFP oonditions. Figures 3.2.1.3-1 to 3.2.1.3-5 show the NSSS response for power,

~

heat f1ux, RCS temperatures, RCS pressure, and steam generator pressure during this event.

For radiological release assessment and potential for loss of shutdown margin, an inadvertent opening of a secondary safety. valve envelopes the events above.

A presentation of the Inadvertent Opening of a Stean Generator Safety Valve or Atmospheric Dump Valve Event is contained in Section 3.2.1.4.

3.2. 1.3. 4 Conclusions For the increased main steam flow events, the DNBR and CTH limits are not exceeded. In addition, the reactivity transient during the event is less limiting then the inadvertent opening of a secondary safety valve presented in Section 3.2.1.4.

Inadvertent opening of a single steam dump and bypass valve or atmospheric dump valve, or the opening of the turbine admissiou valve at Hot Zero Power produce consequences less severe than opening of the turbine admission valves at HFP.

The radiological consequences are bounded by those presented in Section 3.2. 1.4 (Inadvertent Opening of a Steam Generator Safety Valve or Atmospheric Dump Valve) .

64

TABLE 3,2,1,3 1 KEY PASO%TERS ASSUMED FOR THE INCREASED MAIN STEAM FLOW EVENT

'aruneter Units Value Total RCS Power (Core Thermal Power + Pump Heat)

Initial Core Coolant Inlet oF 552 Temperature Inftial Reactor Coolant System psf a 2180 Pressure Inftfal RCS Vessel Flow Rate Ipm 363UOOO Moderator Temperature Coefficient x10 hp/ F 207 CEA Worth at Trip HaO Doppler Coefficient Multiplier .85 65

TABLE "3o2 1+3&

..-'- "'-.- "SE UENCE"OF EVENTS FOR THE INCR EASED MAIN STEAM FLOW Time (sec) '-" Event Set int or Value

~.~r 0 0 -"-.-Turbine Admission Valves Open to 120$ oi tull ilow

~Maximum Flow Capacity 200 3 ..;: Variable- High Power Trip 11Ã of'ull power

• - '.-;-Reactor 20.7 Trip Breakers Open

"., Turbine Trip 21,0 CEAs Begin to Drop in the Core

21. 1 . ".Maximum Power; 116.5%

=--,'aximum Linear Heat Gener ation

':-Rate 15+2 KW/f't 21 ' .Minimum DNBR Occurs (CE-1) 1.34

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3.2 1.4

~ INADVERTENT OPENING OF A STEAM GENERATOR SAFETY VALVE OR ATMOSPHERIC DUMP VALVE 3.2 ~ 1 ~ 0.1 Identification oi Causes The Inadvertent Opening of a Steam Generator Safety Valve (secondary safety valve) or Atmospherio Dump Valve Event was analyzed to assure that:

Reliable control of reactivity is maintained during the event.

2. Two hour .site boundary doses are a small fraction af the 10CFR100 guidelines.

An evaluation of this event with respect to fuel performance oriteria is included in the Asymmetric Steam Generator 'Transients Event (see Section 3.2.7.1)

An inadvertent apcning of a steam generator saf'ety valve (secondary saf'ety valve) or an atmosphere dump valve may be caused by:

A. A mechanical failure in the spring mechanism of a single spring loaded secondary safety valve. This event would result in an increase in main steam flow of'pproximately 750,000 Ibm/hr.

B. Operator error or oontrol system f'ailure resulting in thc apening of a single atmospherio dump valve. This event would result in an increase in main steam f'low of'ess than 300,000 Ibm/hr.

As an cxtrenc example of the above events, an inadvertent opening of a secondary safety valve has been analyzed.

The events described here are a subset of a broader oategory of events referred to as Asymmetric Steam Generator Transients. These events are presented in detail in Section 3.2.7.1, and a discussian of'hese events with respect to the fuel design limits is deferred to that section. However, an inadvertent opening of a secondary saf'ety valve (initiated from Hot Zero Power (HZP))

represents the worst case with respect to radiological release, and loss of shutdown margin ior those AOOs which cause increased heat renoval by the secondary system (Section 3.2.1). Therefore, for completeness, a discussion of radioactivity release, and loss of shutdown margin far the inadvertent opening of a secondary saf'ety valve is presented in this section.

The inadvertent opening ai a secondary safety valve results in thc entire blowdown of one steam gcneratar and partial blowdown of the other. For this reason, the radiological release and cooldown exceeds those experienced in the events presented in Sectians 3.2.1.1 through 3.2.1.3.

3.2.1.4.2 Anal sis of Effects and Canse uences This event was initiated from the conditions given in Table 3.2.1.4-1. These conditions along with the maximum steam generator inventory (corresponding to HZP conditions) were selected to maximize radiaaotivity release and loss af shutdown margin. A minimum CEA worth for Hot Zero Power conditions af

-4.0$ Ao was assumed to be available for shutdown at the time of reaotor trip.

The highest core inlet temperature was used to maximize the total amount of

.72

heat transfer from primary to- secondary and hence maximize the total steam released through the stuck- open second ar y safety valve; The analysis conservatively assumed that thi~baron infected 'by the safety fngectfon system vas 1.0$ Ap per 95 ppm, and that one of the tvo available safety fnSeetfan pips fails to start.

In this analysis, credit vas taken only far the pratective action .of the Lov 5team Generator Level Trip, automatio starting af ane safety fnSeetion pump, operator aotian after 10 minutes to terminate auxiliary feedvater flav (or prevent its initiation if automatio initiation had not yet taken place after 600 sec), and operator action after 30 minutes to commence horatian. to cold shutdovn baron concentration.

!The assumptions used far radiolagical release calculations are given in Table 3.2 0%.

2.2,1.4.3 Results The inadvertent opening af a steam generatar safety valve resulted in. a L'ov Steam Generatar Level Trip at 829.15 seconds. The peak reactivity after trip vas -1.2fdp at 1800 seconds. The degradation of shutdavn margin vas terminated at 1800 seconds by the operator commencing boration to cold shutdavn eonoentration. The resultant site boundary dase is:

Thyroid (DEQ I-131) e 2 REN Whole Body (DEQ Xe-133) ~ 10 mREM'.

The sequence of events for the inadvertent opening af a steam generator safety his presented in Table 3.2.1.4-2. Figures 3.2.1.4-1 to 3.2.1.4-7 shov,the NSSS respanse far core paver, core heat flux, RCS temperature, RCS pressure, steam generator pressure, reactivity, and integrated steam flav.

3.2.1.4.4 Conclusians The results af an inadvertent opening of a steam generator safety valve shovs that reliable control af reactivity is maintained, and that the radiological "dose after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at the site boundary is a very small fraction of'he 10CFR100 guidelines. A further disoussion of Asymetrie Steam Generator Transients, vhich inoludes evaluatian of fuel performance during these events,

'is presented in Section 3.2.7.1.

73

TABLE 3.2.1 ~ 4~1 KEY PARAMETERS ASSUMED FOR THE INADVERTENT OPENING OF A STEAM GENERATOR SAFETY VALVE EVENT INITIATED FROM HOT ZERO POWER Paraaeter Units Value Initial Core Pmrer Initial Core Coolant Inlet OF 535 Temperature Initial Reactor Coolant 2180 System Pressure Initial RCS Vessel Floe Rate 363U000 Moderator Temperature Coefficient x10 4p M <<2e7 CEA Worth at Trip S4o &.0 Doppler Coefficient Multiplier ~ 85 74

TABLE 3i2,1,4-2 SEQUENCE OF EVENTS FOR AN INADVERTENT OPENING OF A STEAM GENERATOR SAFETY VALVE INITIATED FROM HOT ZERO POWER Time (sec) Event Set int or Value 0.0 A Single Steam Generator Safety Valve Fails to the Full Open Position 829 ~ 15 Low Steam Generator Level 5$ oi narrow Signal Generated range tap span 830.3 Trip Breakers Open 830 '4 CEAs Begin to Drop in the Core 1111 ' Pressurizer Empties 1121 3 Safety Infection Actuation Signal t648 psia 1122e3 RCS Pump Coastdcwn Begins 1151 ~ 3 Single Safety In)ection Pump Reaches Full Speed 1366.3 Main Steam Isolation Signal Generated 460 psia 1367.O Main Steam Isolation Valves Begin to Close 1373.0 Main Steam Isolation Valves are Closed 1800. Operator Borates to Cold Shutdown Concentration Peak Reactivity -1.2%

7200. 2 Hour Radiologioal Dose at the Site Boundary:

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a 3+2+1 o5a STEAM SYSTEM PIPING FAILURES: INSIDE CONTAINMENT PRE TRIP POWER EXCURSIONS 3.2 1.5a.1 Idcntificatiah of Causes Faf lures in the main steam system piping vere analyzed to an'sure that a ooolable geometry is maintained and that site boundary doses do not exceed 10CFR100 guidelines.

A rupture fn the main steam systen piping increases steam flaw fram the steam generators. This increase in steam flov increases the rate of RCS heat removal by the stean generators and causes a decrease in oore inlet temperature. In the presence of a negative moderator temperature coefficient af reactivity (MTC), the decrease in core inlet temperature causes core power to increase.

This increase in core power can cause the SAFDLs to be exceeded.

The excursion in core power is terminated by the actian of one of the fallowing Reactor Protective System (RPS) trips: Thermal Margfn/Lav Pressure (TM/LP), Lov Stean Generator Pressure (LSGP), High Power or High Containment Pressure.

3,2.1.5a.2 Anal sis oi Effects and Conse uences Steam Line Breaks (SLB) inside containmcnt .may be postulated to hav~ break areas up to the cross section of the largest main steam pipe (6.305 ft ). In evaluating SLBs inside the containment, cnvironmcntal degradation af the sensors input to the AT power calculator and thc pressure measurencnt sensors is oonsidered. Also considered is the deoalibration of the ex-core neutron detectors caused by the cooler water fn the downcomer region.

. SLBs with severely negative MTC' and large break ai eas, while initially causing a morc severe power excursion are gftfgated earlier by actfon of RPS trips. The earlier action of the RPS trips is oauscd by:

1 ~ The more severe steam generator pressure decrease, accompanying SLBs with large brcak areas, cause~ an early LSGP trip.

2. The increased mass and energy release due to the larger breaks into the contaiment atmosphere causes a more rapid increase in containment pressure and earlier trip.

Consequently, it is necessary to perform the analysis parametric in brcak size and MTC to ensure that the limiting break area is identified.

Table 3.2.1.5a-1 presents the initial conditions used in the analysis of the Inside Containment SLB Event.

h Loss oi AC Power (LOAC) is postulated to accompany the SLB Event. The LOAC causes a coastdown of the reactor coolant pumps. The timing of the LOAC is assumed such that the RPS low flow trip function oocurs at the same time that the primary RPS trip would have occurred without the LOAC assumptian. This timing assumption results in a lowered flov during the time periad vhen the peak pover is reaohed by thc transient and maximizes calculated potential fuel damage sinoe earlier timing of the LOAC would result in a low flow trip sooner and at a correspandly lover power level. h later timing of LOAC vill result in higher RCS ilaw at the time of peak pawer.

83

3.2.1.5s.3 Results k parametric analysis in both MTC and break arcs was performed on the Inside Containment SLB Event. This parametric analysis idcntif'ied the limiting Inside Containment SLB Event in terms of maximum heat flux before an RPS trip.

The llaltlng lnslde contalnaent RP Event uas found to be'he break cagsfng an ef fectivc flow area of 2.01 ft with an ef fective HTC of -.54x10 hp / F.

Table 3.2.1.5a-2 and Figures 3.2.1.5a-t through 3.2.1.5a-6 present the sequence of'vents for the limiting Inside Containment SLB Event and present the response of the NSSS for power, heat flux, RCS temperature, RCS pressure, steam generator prcssure and reactivity.

3.2.1.5a.4 Conclusions The analysis of'he Inside Containment SLB Event demonstrates that a eoolable geometry is maintained as the number of'uel pins predicted to fail is less <

than 10 percent. Site boundar y doses for the inside containment SLB arc bounded by thc doses obtained in the outside containment SLB analyzed in Section 3.2.1.5b.

84

TABLE 3e2e 1 e5a 1 KEY PARAMETERS ASSUMED FOR THE STEAM SYSTEM PIPING FAILURES EVENT INSIDE CONTAINMENT PRE>>TRIP POWER EXCURSIONS Parameter Units Value Total RCS Power (Core Thermal Power

+ Pump Heat)

Initial Core Coolant OF 552 Inlet Temperature e

Initial Reactor Coolant 2180 System Pressure Initial Steam Generator Pressure psia 910 CEA Worth at Trip %hp 7e3 Effective Moder ator Temperature X10 ApM M 7 to -.27 Coefficient

~ 0060 85

TABLE 3.2.1.5a-2 SE UENCE OF EVE S FOR THE STEAM SYSTEM PIPING FAILURE EVENT INSIDE CONTAINMENT PRE-TRIP PONER EXCURSIONS Time (sec) Event 0 0 Failure in the Main Steam System 2.10 A,2 Piping 36.2 LOAC on Turbine Trip, Reactor Coolant Pumps Begin to Coastdown 36.3 Maximum Core Power 136.13$

40 ~ 1 RPS Trip Gener ated, Low Coolant Flow (High oontainment 70$

pressure trip would have occurred at this time without the LOAC assumptions.)

40 75 Trip Breakers Open 41 ~ 09 CEAs Begin to Enter Core 41.7 Minimum DNBR .783 53.7 Sat'ety Infection Signal 1580 psia 54 ~ 8 MSIS Generated on Low Steam 460 psia Generator Pressure 55 4 Empties 'ressurizer 86

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3e2o1o5b STEAM SYSTEM PIPING FAILURES: OUTSIDE CONTAINMENT PRE TRIP POWER EXCURSIONS 3 o2 '1 o5bo 1 Identi ficati n of'auses Failures in the main steam system piping vere analyzed to ensure that a eoolable geometry is maintained and that site boundary doses do not exceed 10CFR100 guidelines.

A" rupture in the main steam system piping inoreases steam flaw f'rom the steam generators. This increase in steam flov increases the rate af'CS heat removal by the steam generators and oauses a decrease in core inlet temperature. In the presence of a negative moderator temperature coefficient oi reactivity (MTC), the decrease in core inlet temperature causes core power to increase.

This inorease in core power can cause the SAFDLs to be exceeded.

The excursion in core paver is terminated by the aotion af one of'hc following Reaotor Protective System (RPS) trips: Thermal Margin/Lov Pressure (TM/LP), Lov Steam Generator Pressure (LSGP), or High Power.

3.2.1.5b.2 Anal sis of Effects and Conse uenccs Break areas for Outside Containment SLBs ar e limited to the area of'he flow restrictors (2.27 ft ) vhich are located upstream af'hc containment penatrations. This limits the severity of the RCS coaldown and the accompanying power excursion. The RPS trips credited arc not subject to an environmental degradation as in thc Inside Containmcnt SLB analysis presented in Section 3.2.1.5a. Based on this f'ctt, the action of these trips terminate the paver excursion earlier for the same break size and MTC.

A Loss of'C Power (LOAC) vas assumed to occur during the Outside Containment SLB Event. The Loss of Power causes the reactor coolant pumps to coast down.

The timing of'he LOAC vas assumed such that a lov flow trip signal is generated at the same time that a high power signal vould have occurred vithout the LOAC assumptian. An= earlier LOAC vould cause the low flow trip earlier vhich vould reduce the heat flux abtained. A LOAC at a later point in time

.would result in a higher flow during the peak pover period of'he event and during the power decay after the trip. Either of these alternate times of'OAC would result in a fewer number of fuel pins predicted to f'ail.

The Outside Containment SLB Event is less adverse than the inside containment break from the standpoint of fuel failures. This improvement is due to the laok of'nvironmental degradation af the RPS systems. Thc most significant assumptian for the RPS system trip setpoints is a low flow trip setpoint of 93$ af rated ilaw rather than the 70$ lov flow trip setpaint used for the Inside Containment SLB Event analysis. The increase in flow at time of trip greatly reduces fuel pin failure. Hovever, the outside containment break is more limiting than the inside containment break in terms of offsite dose as fluid is discharged directly to thc atmosphere.

93

3.2.1,5u.3 Results h parametric analysis in both HTC and break area was performed for the Outside ntainment SLB Event. This parametric identified the limiting Outside Containment SLB Event in terms of maximum heat flux before the RPS trip. A LOhC was then assumed to occur such that a low flow trip occurs simultaneous with the RPS trip credited.

The limitinq case identified was one which resulted in an effective flow area of 2.27 ft . with an effective MTC of -1.08x10 hp/ F. Table 3.2.1.5b-1 presents the initial conditions assumed in the analysis of the Outside Containment SLB Event. Table 3.2.1.5b-2 and Figures 3.2.1.5b-1 through 3.2.1.5b-6 present the sequence of events for the limiting Outside Containment SLB Event and show the response of the NSSS for power, heat flux, RCS temperature, RCS pressure, steam generator pressure and reactivity.

The Outside Containment SLB Event resulted in site boundary doses of 98 Rem to the thyroid and 9¹.2 mRem whole body.

3.2.1.5b.¹ Conclusions The analysis of the Outside Containment SLB Event demonstrates that less than 10 percent of the pins in the core are predicted to fail and consequently. a eoolable geometry is maintained. Site boundary doses are calculated to be a fraction of 10CFR100 guidelines.

94

TABLE 3a2,1 5b-1 KEY PARAMETERS ASSUMED FOR THE STEAM SYSTEM PIPING FAILURE EVENT OUTSIDE CONTAINMENT PRE TRIP POWER EXCURSIONS Pareaeter Total RCS Power Uatta 'alee (Core Thermal Power

+ Pump Heat)

Initial Core Coolant 552 Inlet Temperature Initial Reactor Coolant psia 2180 Systea Pressure Initial Steai Generator Pressure psia 910 Minimum CEA North Available at HFP Sg) ~7a3

. Effective Moderator Temperature &0 Ape Qi7 to e27

. Coeffioient Fraction (Including Uncertainties) ~ 0060 95

TABIZ ~.2. 1.5b-2 PQKiCZ OF PCS 70R 5iE STEM'EU". PIPI?lG FAHURE PIE~

a v Time (sec) Brent ~mt int or Viue 0.0 Failure in the Ihin team +stem 227ft Piping IDAC on Turbine Trip, Feactor Coolant Pumps Begin to Coastdown 14.8 baximum Core Power

15. > RPS Trip Generated Iow Coolan F'w o:;; of'a+ed (High Power trip would have 'Plow been generated without the IDAC assumptior.. )

15.95 Trip Breakers Open 16.29 CEAs Begin to Drop into Core 17.2 Yanimum DIER 1 02H 27.e R~ety Injection Actuation Signal 1650 psia

29. 6 Y IS Generated on los S+eam $ 60 psia Genera+or Pressure 51.2 Pressurizer Enpties 96

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3 2 1 5o STEAM SISTEM PIPING FAILURE POST-TRIP ANALSIS 3.2 1.5e.1 Identification of Causes The Hot Full Power (HFP) and Hot Zero Power (HZP) Steam Line Break (SLB) Events were analyzed ta determine that oritioal heat fluxs are not exoeeded during this event and site boundary dose da not exceed 10CFR100 guidelines.

A break in the main steam system pfpfng fnoreases the rate of heat extraction by the steam generators and causes cooldown of the Reactor Coolant System (RCS) ~ With a negative moderator temperature coetffofent of reaotivfty, the cooldown vill praduce' positfve reactivity additfan. It the break occurs between the steam generators and the isolation valve, blawdown of the affected steam generator continues after Main Steam Line Isolation. Flow fr om the intact stcam generator fs termfnated with closure ot both fsalatfan valves, efther of which is oapable of terminating flaw.

E 3.2.1.5e.2 Anal sis of Etfeets and Cense ences The HFP ease wss initiated at the eondftians listed in Table 3.2.1.5C-1.

The tollowfng considcratfans were also included (applies to both HFP and HZP analysis):

a) reactor trfp is fnitfated by either low steam generator pressure or high power level.

b) The cooldown following a steam line break results fn contraction of the reactor coolant., f For this analysis, f the pressur izer empt fes, the reactor coolant pressure fs set equal to the saturation pressure oorresponding ta the highest temperature fn thc reactor ooolant system.

e) A safety infection aotuation signal (SIAS) fs actuated when the pressurizer pressure drops below the setpoint. Time delays associated with the safety in)ection pump acceleration, valve opening, and flushing of the unboratcd safety fngcetion lines is accounted tor.

d) The cooldown of the RCS fs terminated when thc affected steam gcncrator blows dry. As the coolant temperatures begin increasing, positive reactivity insertion from moderator reactivity feedback dccrcascs. The decrease fn moderator reactivity combined with the negative reactivity inserted via boron infection cause the total reactivity to become more negative. II The Moderator Temperature Coefficient (MTC) af reactivf ty assumed in the analysis oorresponds to the most negative valve allowed by the tech. spec.

This negative MTC results in the greatest pasitfve reactivity addition during the RCS oooldown caused by the steam lfne break. Sinoe the reactivity change assooiated with moderator feedback varies sfgnffioantly over the moderator density covered in the analysis, a curve oi reaotivfty insertion versus density rather than a single value of MTC is assumed fn the analysis. The moderator eooldown curve used fn the analysis was oonscrvatfvely calculated assuming that an reaotor trfp, the hfghest worth control element assembly fs stuck fn the fully withdrawn posf tfon.

103

The reactivity defect associated with fuel temperature deorease fs also based on a most negative Fuel Temperature Coefficient (FTC). This FTC, in oon)unction with the decreasing fuel temperatures, oauses the greatest positive

- reaotfvfty insertion during the steam line break event. The uncertainty on the

..FTC assumed fn the, analysis fs given fn Table 3.2.1.5C-1. The 0 fraction

-assumed is the maximum absolute value including uncertafntfes for end-of-life conditions. This too is conservative since it maximizes subcritical

. multfplioation and thus, enhanoes the potential for Return-to-Power (R-T-P).

l4 The mfnimum CEA worth aisumed to be available for shutdown at the time of reactor trip at the maximum allowed power level fs -7.5$ AP. This available scram worth corresponds with the moderator cooldown curve and stuok rod worth

-.; used in the analysis.

'he analysis assumed that, on a safety fngectfon actuation signal, one high pressure safety infection pump fails to start. A maximum inverse boron worth of 95 ppm/gap was conservatively assumed for safety fnJection.

'o determine a limiting break sfze, two effects, were considered.

" sfzes result in a slower steam generator pressure, drop which delays the Hain Small break Feedwater Isolation Signal (HSIS). This delay and the delayed closure of the Hain Feedwater Regulation Valves followfng reactor trip (thfs delay is part of the Hain Feedwater control circuitry) results'n more feedwater being added to the steam generator following reaotor trip. The increased feedwater (f.e.,

, greater mass) aids in the cooldown of the plant. For larger br eak sizes, the increased mass flow rate results in more heat removal from the RCS (all mass leaving the break fs conservatively assumed to be in the pure steam phase).

. Consequently, a parameteric analysis was performed to. determine the limiting break size. The results show that a break size of 5.2 ft is the limiting HFP SLB event.

.The variable high power trip setpoint and the time of the loss of offsfte power were chosen to maximize the cooldown of the RCS. A variable high power trip setpoint of 105$ of 2700 HWT (107$ - 2$ uncertainty) was assumed fn order to

- generate an earlier trip time. The time of loss of offsite power was assumed to be simultaneous with the main steam isolation signal (HSIS). . This

,assumptfon results fn the coastdown of the main feedwater pumps concurrent with the main feedwater isolation valve closure. The combination of an earlier trip time and delayed fecdwater isolation results fn the most severe cooldown of the RCS.

Mo auxiliary feedwater flow is assumed to enter either steam generator. The affected steam generator will be identified as ruptured, (by the Auxiliary

.""Feedwater Actuation System - AFAS) and therefore isolated. The water level in

- the unaffected steam generator will 'either not decrease to the AFAS setpoint or will increase above the setpofnt, (before the AFAS 3 minute time delay expires) therefore terminating the auxiliary feedwater flow to this steam generator.

=The HZP case was initiated at the conditions gfven in Table 3.2.1.5c-1. The cooldown curve corresponds to the most negative HTC allowed by Tech. Spec. The most negative FTC was also used for the reasons previously discussed.

~P 104

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I I

The minimum CEA shutdown worth available. is conservatively assumed'o be the minimum required Technical Specification'limit of W.OS hp. The analysis also assened that, on safety infection aotuation signal, one high pressure,. safety fn)ectfon pump fails to start. k maximum'nverse boron worth of 90 PPM/%Lp was conservatively assumed for the 'safety fngectfon during the HZP case.

When all CEL's are verified to be fully inserted (during modes 3 and 'stuck 4)'; it is not necessary to assume one (the one of.'h'ighest reactivity worth) fs fn a fully withdrawn position when calculating'shutdown margin.

3.2.1.5O.3 BeSII1tr Table 3.2.1.5c-2 presents the sequence of events for the HFP case 'fnitiated at the conditions given in Table 3.2.1.5c-l;'he response of'he NSSS.for power, heat flux, RCS temperature, RCS pressure, 'steam generator pressure and reactivity is given in Figures 3.2.1.5o-1'through 3.2.1.5c&.

t The results of the transient show that-a reactor high power trip sfIgnal is generated at 5.3 seconds. Low stoma - generator pressure will result in generation of MSIS at 16.2 seconds. Main steam'solation and main feedwater isolation valves begin to close as a "result of MSIS generation ind are completely closed following the maximum allowed Technical Specification. delay times. Occurrence. of loss of offsite .power at . the time of MSIS leads to coastdown of the reactor coolant pumps.

The results of'he analysis show'hat SIhS fs actuated at 20.8 seconds. The affected steam generator blows dry at 131 seconds and terminates th'e cooldown of the RCS. The peak reactivity attained is -.02gp at 159 seconds. 'k peak post trip power of 7.3$ is produced at 160 seconds. The continued production of deoay heat from the fuel after termination of blowdown, causes the reactor coolant temperatures to increase. This fn turn reduces the magnitude of the positive moderator reactivity inserted and thus the total reactivity becomes more negative.

Table 3.2.1.5c-3 presents the sequence- of events for the HZP oase. initiated from the conditions given in Table 3.2.1..5c-1. The response of the'SSS for power, heat flux, RCS temperature, RCS:pressure, steam generator pressur'e and reactivity is given in Figures 3.2.1.5c-7. through 3.2.1.5c-12.

The analysis assumed the loss of offsite power at the beginning of, the event pince this assumption leads to the lowest core flow at the time of.,-return to

'gower and results in a lower calculated DNBR. Reactor trip occurs on lowsteam

~

generator pressure at 3.7 seconds and isF"followed by MSIS at 4.3 seconds.. The olosure of the main steam isolation valves is completed following the maximum allowed Technical Speoifioatfon delay time.

The results of the analysis show that SZAS is aotuated at 26.5 second'i. The affected steam generator blows dry at 128 seconds. The peak reaotivity attained fs +.2$ hp at 200 seconds and,leads to a maximum return to power of

.8~x at 262 seconds. The addition of boron via high pressure safety fn)ection as well as turnaround of core temperatures following the affected steam gener ator 's dryout mitigates the reactivity transient.

Fr K

I 1050',

3.2 $ ,5o.4 Conclusions The Steam Line Rupture Event from HFP and HZP oonditions with loss of offsite power shows that the core does not produce significant instantaneous fission power. Sinoe there is no significant Return-to-Power, critical heat fluxes vill not be exceeded.

it oan be oonoluded that 106

TABLE 3,2,1.5c-1 KEY PARAMETERS ASSUMED FOR THE STEAM LINE BREAK EVENT Parameter 8 Units Full Power Iero Power Total RCS Power, MWt 1 ~0 (Core Thermal Power +

Pump Heat)

Initial Core Coolant Inlet 552 540 Temperature, F Initial RCS Vessel Flow Rate, 363 F000 363,000 GPM Initial Reactor Coolant . 2010 2410 System Pressure C Doppler Coef fioient Multiplier 1 ~ 15 1 ~ 15 Moderator ture 247 M.7 10 ~/ F Temperer Coefficient, CEA North at Trip, $g> -7.5 Inverse Boron Worth, ppm/Qp 90 e

107

TABLE 3.2 ~ 1.5c-2 S UENCE OF EVENTS FOR THE STEAM LINE BREAK EVENT AT HOT FULL POWER INSIDE CONTAINMENT WITH A LOSS OF OFFSITE POWER AND WITH HPSI PUMP FAILURE Time (sec) Evsllt', Set int or Value 0 0 Steam Line Rupture Occurs 5.3 Reaotor Trip Signal Generated on 105'f 2700 MWT High Power 5.7 Reactor Trip Breakers Open 6.04 CEis Begin to Drop into Core 16.2 Main Steam Isolation Signal Generated 060 psia 16.2 Loss of Offsite Power Occurs 20.7 Pressurizer Empties 20.8 Safety InScction Actuation Signal Generated an Low Pressurizer Pressure 1578 psia 21.55 Main Fccdwater Isolation 22.95 Main Steam Isolation Valves Completely Clascd 50 ' HPSI Pump Reaches Full Speed 131 Affected Steam Generator Empties 159 Maximum Post-Trip Reactivity -0 02x10 fd,p 160 Maximum Return to Power 7.3$ af 2700 MWT (consisting of'$

decay heat and 2.3f fission power) 108

TABLE 3.2.1.5c-3 S UENCE OF EVENTS FOR THE STEAM LINE BREAK EVENT

'kT HOT ZERO POWER INSIDE CONTAINMENT WITH A LOSS OF OFFSITE POWER kND WITH HPSI PUMP FAILURE Time (sec) Event Set int or Value 0,0 Steam Line Rupture Occurs Wffiste Poser Lost Wour RCPs CoastdoMn 3.7 Lmr Steam Generator Pressure Trip Signal Occurs 510 psia 4 30 Main Stean Isolation Signal Generated on Low SG Pressure 460 psia 11 05 Main Steam Isolation Valves Completely Closed 26.5 Safety Infection Aotuation Signal Generated on Low Pressurixer Pressure 1578 psia 30 0 Pressurixer Empties 56.5 HPSI Pump'eaches Full 'Speed 128 kffeoted Steam Generator Empties 200 Maximum Post-Trip Reactivity +0 2x10~

262. Maximum Return to Power 0 84$ of 2700 MWT

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9.2+2 DECREASE IN-'HEAT REMOVAL BY THE SECONDARY SYSTEM

$ .2+2+1 LOSS OF 'EXTERNAL LOAD A Loss of Exte'mal'oad is caused by abnormal events in the electrical distribution network which produces a reduction of steam flow from the steam generators to the turbine due to the closure oi the turbine stop valves. The core and system performance following a Loss of External Load would be no more adverse than those following a Loss of Condenser Vacuum, which is described in Section 3.2.2.3. The radiological consequenoes due to steam releases from the secondary system would be less severe than the oonsequences of the inadvertent opening of the secondary safety valve discussed in Section 3.2.1.0. Therefore, a detailed analysis,was not performed.

3 2,2+2 TURBINE TRIP A Turbine Trip is caused by an eleotrioal or mechanical malfunction of the turbine, which produces a reduotion of steam flow from the steam generators to the turbine due to the closure of the turbine stop valves. The core and system performance following a Turbine Trip would be no more adverse than those following a Loss of Condenser Vacuum, which is described in Section 3.2.2.3.

The radiologioal consequences due to steam releases from the secondary system

would be less severe than the oonsequenoes of the inadvertent opening of the isecondary safety valve discussed in Section 3.2.1.4. Therefore, a detailed analysis was not per formed.

3 2 2 3 LOSS OF CONDENSER VACUUM 3.2.2.3.1 Identification of Causes The Loss of Condenser Vacuum event was analyzed to demonstrate that the RCS and main steam system pressures do not exceed 110$ of design values (i.e., 2750 psia and 1100 psia, respectively). The Loss of Condenser Vacuum (LOCV) will oause the turbine stop valves to olose, the main feedwater pumps to trip, and the steam bypass valves to be unavailable. No credit is assumed for a simultaneous reactor trip on turbine trip (due to closure of turbine stop valves) ~ The resulting loss of load and loss of main feedwater cause the steam generator pressure to increase to the opening pressure of the main steam safety valves. The transient is terminated by a reactor trip on high pressurizer pressure.

3.2.2.3.2 Anal sis oi Effects and Conse ences The LOCV event was initiated at the conditions shown in Table 3.2.2.3-1, The combination of parameters shown in Table 3.2.2.3-1 maximizes the calculated peak RCS pressure. . The key parameters for this event are the initial primary and secondary pressures and the moderator and fuel temperature coefficients of reaotivity. The methods used to analyze this event are consistent with those desoribed in the FSAR (Referenoe 7).

The initial core average axial power distribution for this analysis was chosen to be a bottom peaked shape. This distribution is assumed because it minimizes the negative reactivity 'inserted during the initial portion of the scram 122

following a reaotor trip. This will delay reactor shutdown and hence maximizes the p~r ssure transient. A Noderator Temperature Coeffioient (MTC) of 0.0x10 hp / F (the most positive value allowed at Hot Full Power (HFP) by the Technical Specification) and a Fuel Temperature Coefficient (FTC) corresponding to beginning of cycle conditions was used in the analysis. This FTC causes the least amount of negative reactivity feedback to mitigate the transient increase in pressure. The uncertainty on the FTC used in the analysis is shown in Table 3.2.2.3 1. The lower initial RCS pressure is used to maximize the r ate of ohange of pressure. This will maximize peak pressure following trip. The lower coolant inlet temperature and lower steam generator pressure combination result in a more severe secondary transient due to the delay opening of the main steam safety valves. In addition, a loss of offsite power was assumed to occur such that the high pressurizer pressure trip and the low coolant flow trip occur simultaneously. This maximizes the peak RCS pressure following trip.

3,2,2,3,3 Results The LOCV event, initiated from the conditions given in Table 3.2.2.3-1, results in a high pressurizer pressure trip condition at 5.6 seconds. ht 9.5 seconds, the primary pressure reaches its maximum value of 2710 psia (including pump and elevation head) ~ The increase in secondary pressure is limited by the opening of the main stean safety valves, whioh open at 9.3 seconds. The secondar y pressure reaches its maximum value of 1025 psia at 17.0 seconds after initiation of the event.

Table 3.2.2.3-2 presents the sequence of events for this event. Figures 3.2.2.3-1 to 3.2.2.3~ show the NSSS r esponse to power, heat flux, the RCS pressure, RCS coolant temperatures, and steam generator pressure.

The core performance following a. LOCV would be no more adverse than those following a Loss of Normal AC Power, which is decribes in Section 3.2.2.4. The radiologioal consequences due to stean releases from the secondary system would be less severe than the consequences of the Inadvertent Opening of an Atmospheric Dump Valve Event discussed in Section 3.2.1.0.

3.2.2.3.4 Conclusions The results of this analysis demonstrate that the Loss of Condenser Vacuum event will not result in peak RCS pressure or main steam pressure in excess of their respective upset pressure limits.

123

1 s sg 4

S r

ThBLE .2.2. 1 s~

' KEY PAMNETERS hSSUMED FOR THE LOSS OF CONDENSER VhCUUM EVENT Parameter Units Vsins Total RCS Pcwer 2774 (Core Thermal Fever +

Pump Heat)

Initial Core Coolant Inlet OF 535 Temperature Initial Reaotor Coolant System psia 2180 Pressure Initial RCS Vessel Flcnr Rate Spm 363 F 000 Noderator Temperature Coeflioient ')0 hp/ F. 0.0 Doppler Coef'fieient Rultipli,er ~ 85 CEA Worth at Trip W.5 4

4~

n4>>

124

SEQUENCE OF EVENTS FOR THE LOSS OF CONDENSER VACUUM EVENT Time (sec) Set int or Value 0,0 Closure oi Turbine Stop Valves on Turbine Trip due to Loss of Condenser Vacuum 4 7 Loss of Offsite Power 5.6 High Pressurizer Pressure Trip/ 2428 psia/93$ of Lmt Flc¹r Trip 363,000 gpm Analysis Setpoint Reached 6.6 Pressurizer Safety Valves Open 2525 psia 6.75 Trip Breakers Open 7.09 CEAs Begin to Drop Into Core 9.3 Steam Generator Safety Valves 1000 psia Open 9.5 Maximum RCS Pressure 2710'sia 13 ~ 0 Pressurizer Safety Valves 2424 psia Close Total PSV Release 1019 ibm 17.0 Maximum Steam Generator Pressure 1025 psia This value includes pump and elevation head.

125

FLOR IDA N'E'ER PONER 5 LIGHT COo LOSS (F VAQlN 8/ENT FIRNE St. Lucite 2 WITH LOSS (F AC 3I2IL l3 3 Nuclear Power Plant KlK PGER  % TIl'K 126

0 0 l0 Pl FLORIDA LIGHT COe LOSS Y CmIE'SER VAGltl BJBt7 FIHNE St. Lucfe 2 WITH UES OF AC 3 2,2.3-2 Nuclear Power Plant KK HEAT FLN VS TIIK' 27

INLET 0 35 20 TIi'K, SE(VSS POWER FLORIDA 8 LIGHT CO, St. t.ucfe 2

'OSS (F EMBEER VAMJ'I LOSS OF AC B8tt'ITH FIRIK 5.2.2.3-3 Power Plant

'uclear REACmR m0LW +~WE ~Wrimm m~

128

0 FLORIDA R 5 LIGHT COs UKS % NHBEER VMN EVE'lT FIGJRE St. Luc)e 2 NTHUK %AC . 3,2,2.m Nuclear Power Plant HKER (DVHT'HEI) PKKfK % TIfK 129

0 FLORIDA UES OF UFKENSB VAEtl 8/BlT FIGURE POWER 5 LIGHT CO s St. Lucre 2 WITH L%S lf AC 5,?,2.5-5 Nuclear Power Plant SIEN RKRSTOR PRESSURE % TIf'E 130

e 3o2 2+¹ LOSS OF OFFSITE PSKR TO THE STATION AUXILIARIES (LOAC)

%c

.3 2.2.¹.1 Identification of Causes

'he- Loss of Offsite Power (LOAC) Event was analyzed to ensure that the site

. boundary doses would not exceed the 10CFR100 guidelin'es, and the peak RCS pressure does not exceed the upset pressure limit.

Loss of offsite power (LOAC) is defined as a complete loss of offsite

'lectrical power and a concurrent turbine trip. As a result of such an event, electrioal power would be unavailable for the reactor coolant pumps and main feedwater pumps. Under such circumstances, the plant would experience a simultaneous loss of load, a loss of feedwater and a loss of forced reactor coolant flow.

The LOAC is followed by automatio startup of the emergency diesel generators.

The power output of each is suf fioient to supply electrical power to all 4 engineered safety features and to ensure the oapability of establishing and

'aintaining the plant in.,a safe shutdown condition. Since emergenoy power is not available for the oontrol element assembly drive mechanisms (CEDM's) ~ the

" deenergization of the CEDN magnetic holding coils releases the CEA's and allows them to drop into the core. Thus, the possibility of oore damage is prevented by the prompt tripping of the reactor. Thii analysis conservatively assumes that the CEAs do not drop until the reactor is tripped by a low reactor coolant flow rate signal.

Subsequent to reaotor trip, stored heat and fission product decay heat must be dissipated. In the absence of forced reactor coolant flow, convective heat transfer through the core is maintained by natural circulation. Initially, the residual water inventory in the steam generators is used and steam is released

. to the atmosphere via the steam generator safety valves. Subsequent to the availability of Istandby power, plant cooldown is controlled via r emotely-

operated atmospheric steam dump valves.

3.2 2.¹.2 Anal sis of Effects and Conse ences The analysii was performed assuming the initial conditions presented in Table 3.2.2.¹-1. The following aisumptions have been made for this transient:

. A) At time zero, when'" offsite electrical power was lost to the station auxiliaries, the following assumptions were made:

1) The turbine stop, valves close, and the area of the turbine admission valves is instantaneously reduoed to zero;

2) The steam generator feedwater flow to both steam generators is instantaneously'reduoed to zero.

3) The reaotor ooolant pumps begin to coast down. - Following coastdown, the coolant flow'ecessary to remove decay heat is maintained by natural ciroulation,'31

4) Charging pumps on, no letdown flow, and the pressurizer heaters on.

5) Emergency diesel generators start automatically after the loss of all non~ergency AC power.

Lssumptions one through four (as well as a conservatively assumed low flow trip delay time of 1 ~ 15 seconds) maximized the peak RCS pressure for this event.

B) Manual action was taken to aotuate the steam generator atmospheric steam

'ump valves 30 minutes subsequent to initiation of the event to 1nitiate plant cooldown to 300 F.

During the event, two sources of radioaotivity contribute to the site boundary dose: The 1nitial aotivity in the steaa generator and the act1vity associated with primary to secondary leakage. The analysis assumed that all of the initial aotivity in the steae generators and that fraotion of the primary ~

activity leaked to the secondary due to the maximum tube leakage allowed by the Technioal Specification are released to the atmosphere with a decontamination factor of 100, resulting in a conservative assessment of the site boundary dose during the transient.

To determine the maximum possible radioactivity release associated with a loss of offsite power, the following additional assumptions are made:

1) 'ffsite power is not restored and <<ction 1s in1tiated to put the plant in a cold shutdown condition;

2) The reactor coolant system speoi f1c activity equals the Technical Specification limit of 1.0 uC1/gm (I-131 Dose Equivalent Curies);

3) The secondary system specifio activity equals the Technical Specification limit of 0 1 uCi/gm (I-131 Dose Equivalent Curies);

The primary to secondary leak r ate 1s the Technical Specification Limit of 1 gpm (0.5 gpm per steam generator).

5) Atmospheric steam release is required until the reactor coolant temperature is reduced to the point where shutdown cooling can be initiated at 300 F.

6) Primary coolant leak into secondary side fully flashes.

7) For the water steam interface in the steam generators, a decontamination factor of 100..is used.

These assumptions increase the total steam release calculated and thus maximi.xe the predicted doses. In determining the site boundary dose, the thyroid and whole body doses were conservatively calculated. For the purpose of the thyroid dose calculation, it was assumed that all leakages and releases during a given period of time occur instantaneously at the end of the period. In addition, the concentration in the steam generators was based on the minimum liquid mass occurring during that period.

132

Aim

$ ,2,2,t 3 ttttltt.'able

- 3.2.2.4-3 represents the sequence of events for the LOhC analysis.

Tables 3.2.0< presents the assumptions for the radiological evaluation.

Figures 3.2.2.4-t -"through 3.2.2.4-5 show the NSSS response for power, heat flux, RCS temperature, RCS pressure and steam generator pressure during the transient. The peak RCS pressure obtained was 2604 psia, which is well within the 2750 psia upset pressure limit. The two hour and entire event doses for both thyroid and whole body are well within the aoceptance guidelines and are listed in Table 3 2 2,4M 3.2.2.4.4 Conclusions From the analysis, it oan be oonoluded that the Loss of Offsite Power Event, initiated at the conditions presented in Table 3,2.2.4 1 lead to radiological exposures which are a small fraction of 10CFR100 guidelines and that the RCS i peak pressure does not exceed the upset pressure limit of 2750 psia. For the first few seconds of the transient, the Loss of Offsite Power Event behaves like the complete loss of forced primary coolant flow event. Hence, the transient DNBR variation for this event is bounded by the value reported for the Loss of Flow Event (Section 3.2.3.2).

l33

TABLE 3s2.2 4 1 KEY PARAMETERS ASSUMED FOR THE LOSS OF OFFSITE POWER EVENT Paraneter Units Total RCS Power (Core Thermal Power +

Pump Heat)

Initial Core Coolant Inlet Temperature Initial RCS Vessel Flow Rate Spm 363,000 Initial Reaotor Coolant System psia 2410 Pressure Eiieotive Moderator Temperature x10 hp/ F 0 5 Coeifioient Doppler Coeiiicient Multiplier .e5 CEA Worth at Trip Shp 7.0 134

TABLE 3+2 2.4M RADIOLOGICAL EXPOSURES AS A RESULT OF A LOSS OF OFFSITE POWER Paraasttr Dose (rem)

LPZ Thyroid Oi05 ~ 06 Whale Bady ~ 0014 ..0055 135

TABLE 3.2.2e4-3 SE UENCE OF EVENTS FOR THE LOSS OF OFFSITE POWER ANALYSIS Time (sec) Event Set int or Value 0 0 Instantaneous Loss of a Feedwater Flow to Both Steam Generators Loss of Oiisite Power 0 76 Low Flow Signal Generated 93$ oi Rated Flow 1 ~ 91 Reactor Trips Due to Low Flow E

4,0 Pressurizer Safety Valves Open 2525 psia 3 Peak RCS Pressure. 2600 psia>>

5.3 S. G. Safety Valves Open t000 psia>>>>

6.5 Pressurizer Safety Valves Close 2420 psia 25.5 AFAS Generated 5$ Narrow Range Oa5,5 Auxiliary Feedwater Begins to 250 gpm be Delivered Includes pump and elevation head MSSVs cycle open/close 136

0 260 7N 10%

Trrz, seams FLORIDA POWER 4 LIGHT COi FI"<WE St. Lucite 2 3,2,2,0-.1 lear Power Plant 137

0 520 780 1M VN l5% lr.0 zrx, xcmzs FlOR1DA:

4 $ 1GHT COe

'OWER %sh%'i3iR m~ ~f St. Lucfe 2 Pawer Hant 'hcliar mr@~

OUTLET INLET "GO 520 FLORIDA POWER I LIGHT COe sWAFIQ, TA .

St. Luc)e Power Plant 2'uclear AFACm mauen SkW'S/ TURES 4 TItK 139

2670 2525 E

bP 0 260 780 1$ A TIf"E, SECOlIE FLORIDA POWER 5

'4t.

lIGHT COe.  % 5APPi'UM . FIR%

. Lucre 2 thc1ear Power Plant AEACP)R GHlNT k I PKSRIAE 4 TI>E 5,2,2,Q 140

570 0 7X 39$

TIl'K, SEC'f ES FLORIDA HER 4 LIGHT COI

.St. Lucfe 2

% SAT o' ILIN1I ear Power Plant sm aae~f p K US.TIK 141

3 2 2 5 LOSS OF NORHhL FEEDWATER h Loss of Normal Feedwater flow is defined as a reduction in feedwater !'low to the steam generators when operating at power without a corresponding reduction in steam flow from the steam generators. Due to several failures, a complete Loss o!'ormal Feedwater flow oan result from the loss of all main feedwater

.pumps or closure of all main  !'eedwater control valves. In manual feedwater control, closing the feedwater control or isolation valves csn also result in a complete loss of normal feedwater flow. The core and system per formance following a Loss of Normal Feedwater would be no, more adverse than those following a Loss of'ondenser Vacuum, which is desoribed in Section 3.2.2.3.

The radiological consequences due to steam releases !'om the secondary system would be less severe than the consequences of the inadvertent opening of a secondary safety valve discussed in Section 3.2.1.4. Therefore, a detailed analysis was not performed.

l42

3.2.2.6. 1 Identification of Causes a

The Feedwater Line Break Event with a Loss of AC vas analyzed to ensure that the DNBR limit is not exoeeded, the site boundary doses would not exceed a small fraction of the 10CFR100 guidelines, and the peak RCS pressure does not exceed the upset pressure limit.

A Feedwater Line Break Event is defined as the failure af a main fcedwater system pipe during plant operation. A rupture in the main feedwatcr system rapidly reduces the steam generator secondary inventary oausing a partial loss of the secondary heat sink, thereby allawing heat up of the Reactor Coolant System (RCS). The RCS is protected from over-pressurization by the high pressurizer pressure trip. A Loss of AC (LOAC) at time af trip causes eleotrioal power to be unavailable for the reactor ooolant pumps. Under such eiremstances, the plant would experience a loss af forced reactor coolant f1av. Subsequent to reaotar trip, stared heat and fission product deoay heat must be dissipated via convective heat transfer.

If the feedwater line rupture occurs between the steam generator and the feedwatcr line check valves, blowdovn af the affeoted stean generator continues until the steam generator pressure equals the containment back prcssure.

However,. termination of f1ov fran the intact stean generator as well as the intaot lines on the damaged steam generator occurs with olosure of the oheok valves.

3.2.2.6.2 Anal sis of Effects and Cense uences The analysis of the Feedwater Line Break Event was performed using the initial oondltlon shown [n Table 3.2.2.6-t. 6 psrsnetrjo study showed that a break area of 0.30 ft along with the above initial conditions maximized the RCS pressure spike following reactor trip. The following assumptions vere also made for this transient:

h) At time zero:

The steam generator feedwatcr flov to both steam generators is instaneausly reduced to zero.

2) Charging pumps on, no letdawn flow, and thc pressurizer heaters on; these assumptions maximize the RCS pressure spike.

B) At the time of reaotor trip:

1) A lass of AC accurs concurrent with trip and the reactor coolant pumps begin to coast down. Following coastdovn, the coolant flow necessary to remove decay heat is maintained by natural circulation.

2) Emergency diesel generators start autanatically after the loss of all non-emergency AC power.

3) Auxiliary feedwatcr is not available until 420 seconds after initiation af AFAS an lov stean generator level.

143

During the event, two sources of radioactivity contribute to the site boundary dose. The initial Technical Speoification (Tech. Spec.) aotivity in the steam generator and the activity .associated with the maximum Tech. Spec. allowed primary to secondary le4k rate. The analysis assumed that all of the initial activity in both steam generators and the activity added due to the Tech.

Spec. allowed primary to secondary leak rate tube leakage are released to the atmosphere with a decontamination factor of 1.0, resulting in the maximum site boundary dose during the transient.

Table 3.2.0< shows the key paraneters assumed for the radiological evaluation.

To determine the maximum possible radioaotivity release associatg with a Feedwater Line Break Event concurrent with a loss of off'site power, the following additional assumptions were made:

Offsite power is not restored and action is initiated to bring the plant to a cold shutdown condition; t

2) The reactor coolant system specific activity'quals the Technical Specification limit of'.0 uCi/gm (l-131 Dose Equivalent Curies);

3) The secondary system speci fio activity equals the Technical Specification limit of 0 ~ 1 QCi/gm (I-131 Dose Equivalent Curies);

The primary to secondary leak rate is the Technioal Specification Limit of 1 gpm (0.5 gpm per steam generator).

5) Assumed lower feedwater nozzle level increases leak out of break.

These assumptions increase the calculated steam and aotivity release, thus maximizing the predicted doses. For the purpose of the thyroid dose oalculation, it was assumed that all leakages and releases during a given period of time occur instantaneously at the end of the period. In addition, the concentration in the steam generators was based on the minimum liquid mass occurring during that period.

3.2.2.6.3 Rssults Table 3.2.2.6-3 represents the sequence of'vents for the Feedwater Line Break Event with a Loss of AC.

Figures 3.2.2.6-1 through 3.2.2.6-7 show the NSSS response for power, heat flux, RCS temperature, RC pressure, steam generator pressure, pressurizer liquid level and integrated feedwater flow during the transient. The peak RCS pressure oalculated during the Feedwater Line Break Event with a Loss of AC was 2727.0 psia. This value includes the pump and elevation head and is below the 2750 psia upset pressure limit. The DNBR calculation resulted in a value greater than 1.31 which is greater than the 1.28 limit. The event doses presented in Table 3.2.2.6-2 for both thyroid and whole body are within the acceptance guidelines.

144

RR ll 1 RS j,l Aj'"

RSR"*

R l =1 V

-0 R '!

3.2.2.6.4 Conclusions the analysis, a Loss of hC it oan be initiated at the oonoluded that the Feedwiter Line Break Event with 1'rom conditions given in Table 3.2.2.6-1 will not- lead to a DNBR that is less than the design limit of 5 28 during the transient, the radiological consequences for this event are a mall fraction of 10CFR100 guidelines, and the RCS peak pressure does not excleed the upset pressure limit of 2750 psia.

1'jjl J*

S 1j 1

1, SR l45 1 RR S

TABLE 3,2,2.6 1 KEY PARAMETERS ASSUMED FOR THE FEEDMATER LZNE BREAK EVENT PSIS'ddtdl'otal Unttd VS1US RCS Power (Core Thermal Power

+ Pump Heat)

Znitial Core Coolant Znlet 552 Temperature Initial RCS Vessel Flow Rate 363,000 Znitial Reaotor Coolant System psia 2180 Pressure Moderator Temperature Coeffioient x10 hp/ F 1 ~0 Doppler Coefficient Multiplier ~ 85 CEA North at Trip -7.0 l46

3o2o2o6-2 RADIOLOGICAL EXPOSURES AS A RESULT OF A FEEMATER LINE BREAK MZTH LOAC Parroter Dase (rem)

LPZ Thyroid 2 05 0 ~ 90 Whole Body ~ 0014 ~ 0055 147

TABLE 3.2.2. 6-3

~>>CZ QF PPli 8 POP. FZEZLlhE K%4; AT'.AL'H ..

~ it>. ' J ~ t Tine (sec) Brent Se+ int or Value 0.0 Break in th thin Feedwater Line 0.30 ft Instantaneous Loss of Peedwater Plow to Both Steam Generators

18. 2 Heat Transfer Rampdown Begins in 26000 ibm Afected Steam Generator 21.28 Hgh Pressurizer Pressure Trip 2465 psia Setpoint is Reached 22 43 CZAs Begin to Drop Loss of AC Power 23.1 Primary piety Valves Open 2525 psia 23 9 Ievel in Affected Steam Generator Goes Belcri the Assuned nozzle Ievel 500t ibm Steam Would Fiow Be Blown Out of Bre&

26.9 thximum RCS Pressure 272~i+ ps i.".

30.0 Iow Ievel Reached in Una fected 5+ of Ilarrow Generator Initiating AFAS Fannie Tap +on 35 8 Unaffected Steam Generator Safety 1010 psia Valves Open

84. 2 Heat ransfer Rampdmtn Begins in Un'cted team Generator 26000 ibm 160. Iow Stem Generator Pressure 460 psia, Setpoint Reached, NSIS is Actuated 223.0 Level in Unaffected Steam Generator Goes Below the Assumed Nozzle Ievel 5000 ibm 301. 8 Primary Safety Valves Open 2525 450.0 Auxiliary Peedwater Begins to be Delivered to Un~+fected Steam Generator 691. P~imum Pressu.izor Liquid Vacuums 12"5 ft-'ncludes pump and el ation head 148

0 0 7A TIK, SEOMS FLORIDA

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75 gA 28 i2 50 LLa B

0 0 %9 ~50 TI%, SECVtDS

GLOR I DA FEEENKR LINE BREAK POWER 5 L?GHT COI BJEfl'H)

St. Lucfo 2 LOSS V 4C Nuclear Power Plant C0RE IBT FLIN % TIl'K 150

FLORIDA O'E HKK 8/BtT R 8 LIGHT COs FEEDNTER FIKI St. Lucite 2 CIH LOSS V AC 3,2,2,6-'5 Nuclear, Power Plant FEAClQR COOPT M)IBIKKPATlJPG VS TIK 151

2600 0

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0 193 fF)

FLORIDA FEEDOtER UfK BKK 8/BlT.

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155

3o2o3 DECREASE IH REACTOR COOLANT FLOWRATE 3 2.3o3 PARTIAL LOSS OF FORCED REACTOR COOLANT FLOW

, Partial loss of forced reactor flow is oaused by loss of .electrical power to one or more of the reactor'coolant pumps. This is caused by the opening of a reactor coolant pump power supply circuit breaker or the loss of a 6.9 KV bus.

The core and system performance following a partial loss of forced reactor coolant flow would be no more adverse than those following a total loss of forced reactor coolant flow discussed in Section 3.2.3.2. Therefore, a detailed analysis was not performed.

156

..2-3.2 TOTAI: IOe.. OF FO~m mCTOR COOIAIZ Prying 3.2.3.2.1 Identification of Causes Ke Ioss of Coolant H.ow {LCF) Event is analyzed to determine the miniate initial margin that must be maintained by the Iimiting Conditions for Operations (ICOs) such th t in conjunction with the Reactor Protec.ion ~psteT,

{BK), the DHBH limit will not be exceeded.

A loss of nonaal coolant flow nay result either rom a loss of electrical pomr to one or more of the four reactor coolant pumps or from a mechanical failure, such os a pep sh ft seizure. Simultaneous mechanical failure of two or more pumps is not considered credible. 'nder voltage or under frequency of th, motor drive electrical power source can result in e reduction of coolant low; and, if the flow reduction fran either cause is greater than the flow rate +rip setpoint, e reactor trip is initia+ed.

The design of the onsite e'ectrical power system for tho reactor coolant pun~

is such that no single failure from a normal operating condition can cause a complete 4-pznp XlP Brent where the pump-motor- ly+.eel ccnbiration is ..he only available source of coastdown energy. Iwievertheless, for the purpos of ~(his accident evaluation, a cceplete 4-pump LCF is conservatively essxaed.

The 4-Pump IDF Event produces a rapid approach to the DIiBR limit due to .he rapid deere-"xe in the core coolant flow. Protection ag".inst exceedireg the D.'2R limit for this transient is provided by the initial steady state thermal margin which is maint=ined by adhering to the Technical pecifica+ions'CQs 'on D'.~P.

margin and by the response of t¹ HPS.

Reactor trip on loss of coo'an+ flow is initiated by a low coolant ~ o:. rate s.s determined by a reduction in the sum of the stean generator hot +o co'd leg pressure drops. This sign~I is compared wi+h e setpoint which is a func+ion of the number of'nergized reactor coolant pm~. For a loss of flow at ull power operating condi+ion, a trip mll be initia+ed when the flow rate drops to 93 percent of full flow.

3-2.3.2.2 An"- sis of E.facts and Cons uences She transiert is characterized by the flow coes+down curve given in Figure 3.2.3.2-1. Table 3.2.3.2-1 presents the initial conditions assumed in this event. The event is analyzed paranetric on axial shape index, to detemine the maximum required over-power margin needed to ensure the SAFDIa are no. violated.

e. 2..2. 3 Results Table .2.3.2-2 presents the sequence of events or the 4-pep Ioss cf ~ow Event initiated at a shape index of .2. The.low flow trip setpoint is reach~

at .72 seconds and the scram rods ster+ dropping into the core .0"-., seconds later. A minimum ~1 D'BH of'.29 is reached at 2.3 seconds. Fimres 3.2. .2-2 to 3.2.3.2-5 present the core power, heat flux, RCS pressu"e, core coolant tenperatures as a function of time. Figure 3.2.3.2-6 presen+s th hot channel D12P. vs. time for the case that is characterized by an axi".2 shape index of .20.

157

3.2.3.2.4 Conclusions The I@tnt initiated free the Tech Spec LCOs in eonJunetion with the les f leer

'trip util not sxoeed the dtsign DNBR limit.

158

M>> r m4

~"

'-.'. -TABLE 3,2.'3o2 1 KEY"PARAMETERS ASSUHED FOR THE LOSS OF COOLANT FLOV EVENT 4

-4

~,

Parameter

~ Uafts VR1U8 Total RCS Power - l%t 2720 Thermal..Power .'Core

+ Pump Heat)

Initial Core Coolant oF 549+

Inlet Temperature Initial RCS Vessel Flow Rate Cpm n'" 377e500 Initial Reactor 'Coolant psia 2225 System Pressure moderator Temperature Coefficient xlO ~p/ F +.5 4

Doppler Coefficient Multiplier ~ 85 Low Flow Trip Response Time 0.65 CEA Holding Coil Delay sec 0.34 CEA Time to 90$ Insertion sec 2.7 (Including Holding Coil Delay);.-

CEA Morth at Trip (all rods out), -7,0 Total Unrqdded Radial Peaking = -, 1.70 Faotor,(Fr) 4-Pump RCS Flow Coastdown Figure 3.2.3.2-1

>> II' For. DNBR 'caloulations, effects of uncertainties on 'these parameters were combined -

stitistically.

C

, pep L

>1 159

TABLE 3e2,3,2&

S UENCE OF EVENTS FOR LOSS OF FLOW Time (see) Event Set int or Value 0,0 Loss of Pawer to all Four Reaotor Coolant Pumps

~ 72 Low Floe Trip Signal Generated 93$ of Rated Flar 1e37 Trip Breakers Open 1 71 CEAs Begin to Drop into Core 2e3 Minimum CE-1 DNBR 1 28 Q3 Maximum RCS Pressure, psia 2315e2 160

1,0 0

0 TItK, SEOME FLORIDA 5 LIGHT COs~ UjSS OF GXjLNT FLQl 9/ENT St.~ Lucite NK FL% FFACTIN O'TIf'E Nuclear Power Plant 161

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Power Plant 2'uclear I

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166

3.2 3 3 SINGLE REACTOR COOLANT PUMP SHAFT SEIZURE/SHEARED SHAFT 3e2 3 3 ' Identification of Causes The Single Reactor Coolant Pump Shaft Seizure/Sheared Shaft Event (Seized

-'Rotor) vith loss of offsite power, technical specification steam generator tube leakage, failure to restore offsite power in tvo hours, and one stuck open atmospherio dump valve is analyzed to demonstrate that only a small fraction of

=

fuel pins are predicted to fail, and that the maximum ofisite doses are within 10CFR100 guidclincs.

This event can be caused by seizure of the upper or lover thrust-Journal bearings. Loss of offsite power concurrent with the generator trip may be

. caused by a oompletc loss of the external electrical grid triggered as a result of the turbine trip. The loss of offsite power causes a loss of power to the start-up transformers which prevents the plant electrical'oads from being

'ransferred to them from the unit auxiliary transformers. Therefore, thy onsite loads vill lose power and the plant vill experience a simultaneous losh of feedvatcr flow, condenser inoperability, and a coastdown of all reactor coolant pumps. The steam generator tube leak rate is assumed to be at the technical specification value. No credit is taken for restoration of offsite prior to initiation of t

power shutdown cooling.

Additionally, an Atmospheric Dump Valve (ADV) is assumed to stick open at the time of the event initiation. This additional single failure vas considered assuming that the ADVs vill be allowed to operate in the automatic mode.

'peration of the ADVs (in the automatic mode) is prohibited above 15$ of rated power by thc Technical Specification. Therefore, the results of this analysis are conservative based on the current Technical Specification and bounding for automatic operating mode of the ADVs at full power.

3.2.3.3.2 Anal sis of Effects and Conse uences Table 3.2.3.3-1 presents the initial conditions used in this analysis. The value for Moderator Temperature Cocfficicnt is conservatively chosen outside the range allowed by the Technical Specification to maximize the RCS hcatup.

. The methodology used to calculate number of failed fuel pins is oonsistent with approved C-E methodology (discussed in Reference 15).

3.2.3.3.3 Reeu1te In Table 3.2.3.3-2 the sequence of events are shown ior the Seized Rotor Event vith loss of offsite povcr, failure to restore offsite power for tvo hours and one stuck open atmospheric dump valve. Figures 3.2.3.3-1 through 3.2.3.3-4 present the dynamic response of thc NSSS power, heat flux, -RCS temperatures, and RCS pressure during thc transient. Table 3.2.0-8 presents the assumptions for the radiological evaluation.

167

ipinsconservatively <<flat" pin, census distribution (a'histogram of the number of versus radial peak) is used to determine the number of pins that DNB. The reiults show that the number of fuel pins predicted to 'xperience tail is much less than 10$ .

The two hour thyroid dose at the exclusion area boundary was calculated to be 22 rema L 3.2.3 3.4 Conclusions The evaluation shows that the plant resyonse to a one pump resistance to forced flow (Seized Rotor) with a loss of offsite power, technical specification steam generator tube leakage, failure to restore offsite power in two hours, and one stuok open atmospheric dump valve oauses only a small fraotion of fuel pins to fail~ and that the maximum offsite dose is within the acceptance guidelines.

168

TABLE3233 1 KEY PARAMETERS ASSUMED FOR THE SINGLE REACTOR COOLANT PUMP SHAFT SEIZURE/SHEARED SHAFT EVENT Parameter Units Asiumed Value Total RCS Parer (Core Thermal Poser + Pump Heat)

Initial Core Coolant OF 552 Inlet Temperature Initial RCS Vessel 363U000 Floe Rate Initial Reactor Coolant psia 2150 System Pressure Doppler Coefficient Multiplier 0.85 Moderator Temperature Coefficient w a CEA North at Trip s

169

TABLE 3.2,3 3-2 S UENCE OF EVENTS 'ORRESPONDING TIMES AND

SUMMARY

OF RESULTS FOR SINGLE REACTOR COOLANT PUMP SHAFT SEI2URE/SHEARED SHAFT Time (sec) Evtnt Set int or Value 0 0 Seizure of RC Pump Shaft

-Affected Pump Begins Coastdown 0,0 Inadvertent Opening of ADV 0 05 Reactor Trip Signal Generated 93.0 on Low RCS Flow, $ of'ated Flow 0+70 Trip Breakers Open I

0+96 Turbine Trip on Loss of Power to CEDM Power Supply Buses 1 30 Minimum Transient DNBR 1 t23 2.95 Maximum RCS Pressure, psia 2239 3.96 Loss oi Ofisite Power on Generator Tr ip

-Diesel Generator Starting Signal

-Unaffected RCPs and MA( Pumps Lose Power and Begin Coastdown 451 0 Auxiliary Feedwater Begins to Enter SGs 1800 ~ Operator Takes Control of Available ADVs to Initiate Plant Cooldown (at 75 F/hr)

Operator Closes Aff'ected ADV Block Valve Oper ator Clears SIAS Operator Loads the Following on Safety Bus:

-Instrument Air Compressor charging Pumps

-Pressurizer Heater 170

320 0

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3o2o4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES 3 2 4~1 UNCONTROLLED CONTROL ELEMENT ASSEMBLY WITHDRAWAL FROM A SUBCRITICAL OR LOW POWER CONDITION 3 2 4.1.1 Identification of Causes The Uncontrolled Control Element Assembly Wfthdraval Event from Hot Zero Power (HZP) vas analyzed to assure that the DNBR and Fuel Centerline to Melt (CTM)

Specified Acceptable Design Limits (SAFDLs) are not exceeded.

An uncontrolled sequentfal withdrawal of CEAs is assumed to occur as a result af a single failure in the Control Element Drive Mechanism (CEDM), Control Element Drive Mechanism Control System (CEDMCS), reactor regulating system, or as a result of operator error.

The withdrawal of CEAs adds reaotfvfty to the core causing the core power and heat flux to fncrcase. Since the heat extraction from the steam generators remains relatively constant, there vill be an fncrease in reactor coolant temperature. While a continuous withdrawal of CEAs is considered unlikely,. the reactor protective system is designed to terminate any such transfent before fuel thermal desfgn limits are reached.

3,2,4 ~ 1.2 Anal sfs of Effects and Cons ences The HZP case is assumed to inftfate at a hot zero power critical condition. As the CEAs are withdrawn, the positive reactivity insertian vill cause the pawer to increase. Since the event initiates at zero pawer with no heat being produced fn thy fuel, the heat flux wfll also be zero. If the reaotor power goes above 10 peroent of rated power and the rate of ohange of neutron flux is greater than 1.5 decades per mfnute, a CEA Withdrawal Prohibit (CWP) will be in ftiatcd.

By the time core power rcaohes 1S of rated power, the neutron flux will be increasing at a high r ate. Although a reactor trip is generated by the Variable High Pover trip at 17$ of full pover (includes 2$ paver measurement uncertainty), the core power peaks at approximately 100$ power. The core power peaks after trip due to the RPS electronic and the CEA holding coil delays and the time necessary to insert enough scram reactfvfty to offset the posftfve reactivity insertion. As oore power increases, the tuel temperature vill increase and result in Doppler feedback which vill reduce the peak core power.

Due to the fuel time constant, the core heat flux will lag the core power and consequently result fn a lover yeak. The core power will rapidly decrease as the CEAs are inserted thus termfnatfng the power excursion.

Dur fng the event, the RCS prcssure will increase and fellow the core average temperature rise. Depending an the magnitude of reactivity inscr ted, the temperature rise could inorease the pressurizer pressure above the power aperated relief valve settfng. The action of the pressurizer pressure and level control systems vill moderate the pressure peak.

The input parameters and initial oondftians used fn the analysis are listed fn Table 3.2.4.1 1.

175

The maximum CEA withdrawal rate was calculated by combining the maximum CEA differential worth (3.2x10 hp /inch) and the maximum CEA withdrawal speed of 30 in/min. This maximum.reaotivity insertion would result in maximum power and heat flux peak. The minimum transient DNBR is oalculated using the most adverse DNBR initial conditions.

3.2 4,1 3 Results Table 3.2.4.1-2 contains the sequence of events for the HZP oase for the maximum withdrawal rate. Figures 3.2.4.1-1 through 3.2.4.1-4 present the transient behavior, of the core power, core average heat flux, RCS temperatures and RCS pressure. Peak reactor power of 103'as reached at 40. seconds while the maximum heat flux fraction was 54$ . This case resulted in a'minimum DNBR of'.55 at 40.7 seconds. Also, the analysis shows that the fuel~enterline melt SAFDL is not exceeded and the upset pressure limit of 2750 psia is not approached.

3,2 4~ 1 ~4 Conclusions The analysis of control element assembly withdrawal initiated from HZP shows that DNBR and fuel centerline melt SAFDLs are not violated.

176

TAME 3 2 0.1 KEY PARAMETERS ASSUMED FOR THE HOT ZERO POWER CEA WITHDRAWAL EVENT Parameter .

Units Value

'Initial Core Power Level Initial Core Coolant Inlet OF 535

Temperature

.Initial Reactor Coolant psia 2180

'System Pressure Moderator Temperature Coefficient 10 ~/ F +.5 Doppler Coefficient Multiplier .85

.CEA Worth at Trip SAP Reactivity Insertion Rate x10 hp/sec 1a6 Rod Group Withdrawal Speed in/min 30.0 CEA Differential Worth x10 hp/inch 3.2 177

TABLE 3,2 ~ 4 ~ 1 2

,SE UENCE OF EVENTS FOR CEA WITHDRAWAL FROM HOT ZERO POWER Time (sec) Event Set int or Value 0 0 CEA Withdrml Causes Uncontrolled Reactivity Insertion 38 5 High Fever Trip Signal Generated 17$ of 2700 l%t 38.9 Reactor Trip Breakers Open 39.28 CEAs Begin to Drop Into Core

40. Maximum Core Pcwer 103'f 2700 Wt 40e7 Maximum Heat Flux 54$ of 2700 MNt 40 7 Minimum CE-1 DNBR 2.55 41 5 Maximum Pressurixer Pressure, psia 178

8 25 0

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'uc1ear 180

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3 2,4 2 lNCONTROLLED CONTROL'ELEMENT ASSEMBLY WITHDRAWAL AT POMER 3o2 4e2e1 Identification of Causes The Uncontrolled Control Element iaseably Mithdrawal Event from Hot Full Power (HFP) vas enalyxed to determine that the DNBR and CTM design limits are aot exceeded and that the upset pressure limit of 2750 ysia is not violated.

in uncontrolled sequential withdrawal of CEAs is assumed to occur as a result of a single failure ln the Coatrol Element Drive Nechanism Control System (CHNCS), reactor regulatiag system, or as a result of'perator error.

The withdrawal of CEis adds reaettvity to the core causing the oore power and heat flux to iaerease. Since the heat extraction free the stem generators r eases relatively eoastant, there will be an iaerease la reactor coolant temperature. lfhile a continuous withdrawal of CEis is considered unlikely, the ~

reactor protective system is designed to.terminate aay such transient before

~

fuel thermal design limits are reached.

iyressure withdrawal CEL uyset limit.

eveat eaa The ayproaeh the DNBR and CTN SAFDLs and the RCS action of elther the TM/LP (Thermal Nargia/Low Pressure), variable hlgh paver, high yressurgrer pressure, or axial flux offset trip vill prevent exceeding these limits.

is stated in Section 3.2.0.2 and Ref'er ence 2, the CEL Mlthdrawal Event initiated at rated thermal power is one of the DBEs analyxed to determine a bias factor used in establishing the TM/LP eetyoints. This bias factor, along with conservative temperature, pressure, and power trlp input signals assures that the TN/LP trip prevents the DNBR from dropping below the SAFDL limit (NBRa1.28 based on CE-1 correlation) for a CEA Withdrawal event ~ Hence'his event was aaalyxed for Cyole 2 to generate the bias term input to the TM/LP trip. In order to determine the maximum RCS pressure, an analysis parametric ia CEL withdrawal worth vas also performed. The following section presents the results of this yarmetric for the limiting ease.

3.2 4.2.2 Anal sis of Effects and Cense ences The HFP case la initiated at 102% of rated power and at the Limiting Conditions for Oyeration (LCOs) ~ is the CEis are withdrawn at the yreprograaeed rate, the core power will steadily increase at a rate dependent on the worth of the CEAs.

The withdrawal of CEAs vill cause the axial power distribution to shift to the top of the core. The associated increase in the axial peak is compensated by a decrease ln the integrated radial yeaklng factor. The magnitude of the 3-D peak ohange depends yrimarily on the initial CEL eoaflguration and the initial axial power distribution.

The withdrawal of CEAs vill also cause the neutron flux po'wer measured by the exeore detectors to be deealibrated due to rod shadowing. This deealibration of'xcor e detectors, however, ls partially compensated for by reduced neutron attenuation associated with the moderator density decrease (temperature shadowing) ~

As the core power increases, the fuel temp rature will increase end rem"t in

'egative Doppler reactivity feedback. Ke core average he@+ flux wil" slowly increase and leg the core power by an amount depend n+ on the clad-fuel gag conductance. With the heat flux increes'ng, +he ccrc average tempera .ure will increase at a rate dependent on the film coefficient. With the core average temperance increasing, the moderator feedback will increase or decrease +he rate of reactivity adDition dependirg on whether the MTC is positive or negative. As a result of the increase in core average temp rature, the P.""

pressure will increase. If the CEAs are fully withdrawn before any trip is reached, e new steedy state condition at a higher core power end core average temperature will result. With the turbine still denuding 1KP of rated power, the atmospheric dump end bypass systems will pick up the additional power (load).

Durinc n W&mthdrawal, vi~h the fuel end the RCS heating up, the t!TC (usual'~

negative during power operation) and the Doppler (always negative during power operation) will offse+ pert of the withdrawn WM worth- With the P'S temperature increasing, the pressurizer pressure and the level will increase.

Although no credit is tek n in the en~~~ sis, the pressurizer sprays will partially suppress the pressure increase end the level control system will

~

maintain th programmed 1eve" . For cases where +¹ pressurizer pressure exceeds 24CG psie, a reactor trip will be initiated and the Power Oper~ted Relief Valves (PORV) will open thereby reducing .the number of times gthe pressurizer safety valves are actuated. For this event, the POBVs are assumed to be inoperable. In addition, no credit is allowed for the action of the s+eem dip end turbine bypass valves which would maintain .he steam generator below o00 psia and regrate the average RCS temperature et f32 P.

Assuming a large enough withdm'n VM wor'th, a trip wi'1 occur on either the Vari ble Pugh Power, Axial Ftux Cf se+, 2'./LP, cr High Pressuriz r Pressure .

trip. The emourt of withdrawn CM worth to cause a trip depends on the I~ ",

Doppler, and th position of the CZAs.

The input parameters and initial conditions used in the analysis are listed in able 3.2.4.2-1.

The ~~ i~ CZA withdrawal rate is calculated by combin ng the mex5mu.

differential worth (3.2x10 ~/inch) md the maximum CEA wi~hdrwal sp ed of 3O in/min.

~.2.4.2. 3 Resvlts A parametric study was perf'ormed to determine CM reactivi'.y insertion rate a+.

which Variab e High Power (VHP) trips ard High Pressurizer Pressure (HPP) trips would occur simultaneously. 5his reactivity insertion rate mmcimizes peek HC..

pressure. For higher reactivity insertion rates, e. high power trip would terminate the transient before the RCS pressure approaches the HPF setpoint, resulting in a lower peak pressure. For lower reactivity insertion rates, a HPP +rip terminates the event. while reactor power is at a level below .he 4"=1P trip setpoint, resulting 'in a lower pressure overshoot following trip. he reactivity insertion ate at which HPP and VHP trips occur simultaneous'y ~,. "-

detemined to be .2x10~ ~p/in.

184

Table 3.2.4.2-2 contains the sequence ofgvents for the Hot Full Power case initiated at. a withdrawal rate of 0.2x10 gp /in. Figures 3.2.4.2-1 through 3.2.4.2-5 show the behavior 'of: the oore power, core average heat flux, RCS temperatures, RCS yressure and steam generator,.pressure during the transient.

Peak core power of 117.3$ was reaohed at 28.9 seconds and the peak pressure of 2550 ysia occurred at 30.5 seconds.

3.2.4.2. 4 Conclusions The analysis of the CEL Withdrawal Event demonstrates that the action of the RPS prevents exceeding the fuel SAFDLs and the RCS Pressure Upset 'Limit during an Uncontrolled CEL Withdrawal Event. The radiological consequences of opening

%he atmospheric dump valve or safety valve upon reaotor trip during the most limiting CEL Withdr awsl Event results in a site boundary dose whioh is negligible ccapared to the 10CFR100 guidelines sinoe no fuel failures occur.

185

TABLE 3e2 4.2 KEY PARAMETERS ASSUMED FOR THE CEA WITHDRAWAL EVENT AT HOT FULL POMER Parmeter Uulta Value Total RCS Pomr (Core Thermal Poser +

Pump Heat)

Initial Core Coolant Inlet Temperature Initial Reaotor Coolant psf a 2180 System Pressure Moderator Temperature Coefficient 10 hp/ F +.5 Doppler Coefficient Multiplier .85

CEA North at Trip Shp -5. 8 Riactfvity Insertion Rate x10 hp /sec 0 to 1a6 Rod Group Mithdraval Speed in/mfn 30 0 Maximum CEA Differential Worth x10 hp /fnch 3.2 106

TABLE 3.2 4.2-2 SE ENCE OF EVENTS FOR THE HOT FVLL POWER CEA WITHDRAWAL EVENT Time (sec) Evsllt Set int or Value 0.0 CEA Withdrawal Causes Uncontrolled Reactivity Insertfon 2?.3 High Pressurfxer Pressure Trip Sfgnal 2428 psia Generated High Pomr Trip Signal Generated 112S of 2700 MWt t

28.45 Trfp Breakers Open 28 ?9 CEAs Begin to Drop Into Cor'e

28. 9 Core Polrer Reaches Maximum 11?.3S oi 2700 MWt 29.3 Core Heat Flux Reaches Maxfmrmr 115 5$ of 2700 MWt 30 5 Pr'essurfxer Pr'essure Reaches 2550 psiaI Maximum Pressure includes elevation head.

187

0 20 60 TItK, SEOMS FLORIDA POWER 5 LIGHT COs (EA MIHDNOLB.BIT St. Lucre 2 ~

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0 0

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H0T RJU POP, OUTLET AVERAGE TINLET 20 60 ZX, SEm'tDs FLORIDA h LIGHT COo (R "lITHOfNALBBT KfHNUKS % TItK-

'OWER St. Lucre 2 8EACIGR K0LNT 86EN $ ,2,h,2-3 Power P1ant 'uc1ear 190

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NT RlLL PQIER FLOR IDA POWER 5 LIGHT COe KA %H)NNi BIHfI'fEN FI%fE St. Lucre 2 KKPAIOR PPESSUfK % TPE 3,2.0,26 Nuclear Power Plant 192

3.2.4.5 CEA DRY mme 3.2.4.3.1 Identification of Causes The full lengbh CEA Drop Zvent is reanaQsed to determine the initial thermal margins that must be maintained by the haiti'ng Conditions for Operation (ICOs) such that the MBR and Wel to Centerline Melt (C5Ã) design limits vill not be exceeded o The CEA Drop Event is defined as the inadvertent release af a single or subgroup CEA(s) causing it to drop into the core. The occurrence of an drive mechanism would result in a CEA electrical or mechanical failure in a CZA drop r

The CZA drop event causes an initial decresse in reactor power. Since the heat extraction remains relative+ constant, the average reactor coolant temperature vill decrease. The effect of the decrease in tanperature in con)unction with a large negative moderator temperature coefficient, vill be to return the reactor to its initial power level at a reduced core inlet temperature. AdditionaUy, the core power distribution will be distorted due to the CZA insertion.

The ZCOS are designed to maintain a DHB ratio sufficient+ above the~SPy limit without the necessity for a reactor trip during a CEA drop event.

Operation of the detection systems which are designed to'sense a CEA drop event and to reduce turbine load to a preset value are not assumed in this 'analysis.

The action of the protection system to inhibit CZA withdrawal during a CZA drop event has been credited.

$ .2.4.3.2 sis of Effects and Cons uences ~ ~

This event was analyzed f'r both single and subgroup CEA Drop. The latter case requires the maximum initial margin to be maintained by XCOs and is presented below.

Table 3.2.4.3-1 presents the initial consitions assumed in the analysis.

Additional conservative assumptions include:

a) The CEA drop detection system is assumed to be inoperable. 9he turbine load is not reduced, but is assumed to remain the same as prior to the CEA drop. This results in a pcwer mianatch between the primary and secondary systems, which leads to a cooldown of the RCS. Credit is taken, however, for the fact that the autanatic withdrawal'f the CEAs by the CZDM control system is disabled, as discussed in the previous section.

b) The most negative moderator and fuel temperature coefficients of reactivity're used because these coefficients produce the minizmm RCS coolant temperature decrease upon return to 100 percent power level and thus aMimise I5BR.

193

-"c) Charging pumps and proportional heater systems are assumed to be inoper able during'he transient. This maximixes the pressure drop during the event and minimixes DNBR.

d) All other systems are assumed to be in manual mode of operation and have no impact on this event.

The event is initiated by dropping a full length CEL subgroup over a period of 1 0 second. The maximum increases in radial peaking factors (integrated and planar) in either rodded or unrodded planes are used in all axial regions of the core once the power returns to the initial level. Values oi 19 percent are assumed, for these peak increases. The axial power shape in the'hot channel is assumed to remain unchanged and, hence, the increase in the 3-D peak for the maximum power is directly proportional to the maximum increase in radial peaking factor of 19 percent. Since there is no trip assumed, the peaks will stabilize at these asymptotic values after a few minutes as the secondary si+

continues to demand 100 percent power.

3,2,2,3,3 Results Table 3.2.¹.3-2 presents the sequence of events ior the Full Length . CEA Subgroup Drop Event initiated at the conditions described in Table 3.2.¹.3-1.

. The event was analyxed parametric on axial shape index to determine the maximum required overpower margin needed to ensure the ShFDLs ar e not violated.

Figures 3.2.¹.3-1 through 3.2.¹.3-¹ show the NSSS response for core power, core heat flux, RCS temperatures, and RCS pressure. Figure 3.2.¹.3~ shows the minimum DNBR versus time for a limiting CEA drop.

k minimum CE-1 DNBR of 1.28 is obtained at 262 seconds. k maximum allowable initial linear heat generation rate of 17.2 kV/it could exist as an initial condition without exceeding the Acceptable Fuel Centerline Melt Limit of 22.0 kM/ft during this transient. This amount of margin is assured by setting the linear heat rate related LCOs based on the mre limiting allowable linear heat rate for LOCh (13.0 KM/ft, aee Section 3.3).

3.2.¹.3.¹ Conclusions This event initiated from the Tech Spec LCOs will not exceed the DNBR and CTM design limits.

194

TABLE 3.2.4.3-1 KEY PARAMETERS ASSUMED FOR THE FULL LENGTH CEA DROP EVENT Paraaeter Units V81U8 Total RCS Power 272O+

(Core Power +

Pump Heat)

Initial Core. Coolant 549 .

Inlet Temperature Initial Reactor Coolant psia 2225 System Pressure Initial RCS Vessel 377e500 Flow Rate Moderator Temperature Coefficient x10~hoW M.7 Doppler Coefficient Multiplier 1. 15 CEA Insertion at Maximum Allowed 5 Insertion of 25 Power Bank 5 Dropped CEA %orth $ 4o unrodded .15 PDIL -. 15 Integrated and Planar Radial Qnrodded Region 1. 19 Peaking Distortion Factor Bank 5 Inserted 1.19 Region For DNBR.calculation, effects of uncertainties on these parameters were combined statistically.

195

TABLE 3 2.¹.3-2 SEQJENCE OF EVENTS FOR FULL LENGTH CEA DROP Time (sec) Event Set int or Value

.0 ~ 0 CEA Begins to Drop into Core 1 ~ 0 CEA Reaches Full Inserted Position 100S Inserted 1.3 Core Power Level Reaches Minimua and 75.8% of Initial Begins to Return to Power due to .

Reaotivity Feedbecks t

¹0,0 Core Power Returns to its Maximka Value 100S of Initial 78 F 00 Core Inlet Temperature Reaches a New 5¹3. 8F Steady State Value 262 Reactor Coolant System Pressure Reaches 2163 ~ 0 New Steady State Value Minimum DNBR is Reached 1.28 196

FLORIDA R 5 l.lGHT COI RJLL t8lRH KA DR3P B8lT St. Lucre 2 ONE RWB YS TV'E Nuc1ear Power Plant

0 350 ZO TIK, SE(RES FLORIDA

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3 2 ¹o¹ CVCS MALFUNCTION (INADVERTENT BORON DILUTION) 3 ~ 2.4.4.1 Identification of Causes The Boron Dilution event was analyzed to determine the setpoints of the startup channel alarms for protection against an Inadvertent Boron Dilution event in MODES 3, 4, 5 and 6. The setpoints were ohosen to ensure that the criteria for the time between alarms and the loss of shutdown margin are met.

The event is initiated due to inadvertent pumping of unborated water via the charging puaps into the RCS. The unborated water causes a dilution to take plaoe, with a net impact of inserting positive reactivity. The positive reaotivity inserted will cause the power, temperature, and pressure to rise.

3 2.¹.4.2 Anal is of Effects and Conse ences The analysis assumed complete mixing in the RCS. The rate of change of boron ooncentration during dilution is described by the following equation:

M dc i dt

-WC (3,2.4.4-1 )

where M ~ RCS mass C a RCS boron concentration W a charging mass flow rate of unbor ated water The solution of equation (3.2.4.4-1) can be written I

C(t) ~ C(o) e (3.2.4 ~ 4-2) where T a M/1 a boron dilution time oonstant C (o) -" initial boron concentration The ohange in boron concentration is

~C(t) C(o) - C(t) (3.2.4 4-3) or ZC(t) ~ C(o) 1 - e (3.2.4.~)

reactivity insertion is given by and the Reactivity Insertion (t) a IBM C(o) 1 - e

-t/ (3.2.4. 4H) where ZM e Inverse Boron Worth 202

The time required to dilute to criticality is given by Tav. An-C(o)

Corit (3.2.4.~)

vhere Ccrit

• critical boron concentration Equation 3.2.4.4.H @as used to generate a table of reaotivity insertion versus time, free initiation of the event until critioality. Alarm setpoints vere chosen to ensure that the minimun time ciriterion to lose shutdown margin was preserved. The reactivity insertion, corresponding to the time mentioned above ms used to generate the startup channel alarm setpoint.

Table 3.2.4.4-1 shows the key parameters assaaid in the Inadvertent Bor on Dilution analysis.

For Hodes 3, 4, 5 and 6, all three charging pumps mre assumed to be on at their maximum rate; 44 gab'min per pump, for a total of,, 132 gaI/min. For Hode 5 'with a par tially drained r eactor coolant system, one charging pump was assigned operating at its maximua rate.

3.2.4.2,3

~ ~ ~ Results 3 Table 3.2.4.4-2

~ ~ shorn the time available'to the operator to stop the event from the alarm annunciation until criticality occurs, and the criteria for minimum time from alarm annunciation to loss of the shutdown margin.

3.2.4.4.4 Conclusion Table 3.2.4.4M shows that the startup channel alarm setpoints vere ohosen to ensure that the" cirteria to lose shutdown margin during an Inadvertent Boron Dilution event ar e met.

203

TABLE 3,2 4,4-1 KEY PARAMETERS ASSUMED IN THE INADVERTENT BORON DILUTION ANALYSIS Parameter Critical Boron Concentration, PPM (All Rods Out, Zero Xenon)

Hot Standby (Mode 3) 1900 Hot Shutdown (Mode 4) 1900 Cold Shutdown (Mode 5) 1900 Refueling (Mode 6) 1325 Inverse Boron North, PPM/$ Ap Hot Standby Hot Shutdown 55 Cold Shutdown 60

. Refueling 100 Minimum Shutdown Margin Assumed, Qp

.Hot Standby &,0 Hot Shutdown -4.0 Cold Shutdown ~3 '

Refueling -3.95 204

TABLE 3+2+4 4-2 RESULTS OF IBE INADVERTENT BORON DILUTION ANALYSIS Time Avaf1 able Critcrfon for Mfnfmun Time Free Alarm h ce Alarm Annunciation to Annunciation to Loss of'rescr ibed Mod e Criticalit (min) Shutdown Mar in (min)

Hot Standby 15 15 Hot Shutdown 15 Cold Shutdown 15 Cold Shutdown 15 (RCS Partially Drafned)

Refuelfng 30 30

'05

3,2,4,5 STARTUP OF AN INACTIVE REACTOR COOLANT PUMP EVENT The Startup of an Inactive Reactor Coolant Pump Event @as not analyzed because the Technical Specifications do not permit operation at power (Modes 1 and 2)

Wth less than four reactor ooolant pump operating.

206

.3.2+4.6 CONTROL ELEHENT ASSEMBLY EJECTION 3.2.4.6.1 Identification of Causes The Control Element Assembly (CE!L) EJeetfon Event is analyzed to determine the fraotion af fuel pins that exceed the criteria for incipient centerline melting and radial avcragc enthalpy.

Rapid education of a CEA from the core would require a complete circumferential break of the control element drive mechanism (CEDM) housfng or of the CEDH nozzle on the reactor vessel head. The CEDH hausing and CEDM nozzle are an.

extensfon of the reactor coolant system boundary and designed and manufactured to Section III of the ASME Boiler and Pressure Vessel Code.. Hence, the occurrence of such a failure fs considered highly unlikely.

A typical CEA egectfon transient behaves in the following manner: After eJection of a CEA from a Hot Full Power (HFP) or Hot Zero Power (HZP) fnf.tfal condftian, the care power rises rapidly for a brief period. ~

'critical)

The rise is terminated by the Doppler effect. Reactor shutdown is initiated by the high power level trfp, terminating the power transient.

The core is protected against severe fuel damage by the CEA insertions permitted at varfous power levels by the Fewer Dependent Insertion Limit (PDIL) Tech. Spec. and by the high power, trfp.

3.2.4.6.2 Anal sis of Effects and Cense uences The analytical method employed fn the reanalysis of this event fs the NRC approved Combustion Engineering CE!L egection method which fs described in CENPD-190A, (Reference 11).

The key parameters used in this event are listed in Table 3.2.4.6-1 ~ fifth these key parameters, selected to add conservatism, the procedure outlined ip Figure 2-1 af Reference 11 fs then used to determine the average and centerline enthalpies in the hottest spot of thc fuel rod. The calculated enthalpy values are compared to threshold enthalpy values to determine the anount of fuel exceeding these thresholds. Thcsc thr cshold enthalpy values are (References 12, 13, 14):

Clad Damage Threshold Total Average Enthalpy = 200 cal/gm Incipient Centerline Melting Threshold Total Centerline Enthalpy = 250-cal/gm Ful'y Holten Centerline Threshold Total Centerline Enthalpy = 310 cal/gm Fuel exceeding these thresholds are assumed to fail for the purpose of establishing site boundary doses. To baund thc most adverse conditions during the cycle, thc most limiting af cithcr the Beginning of Cycle (BOC) or End'f Cycle (EOC) values of kcy parameters were used fn the analysis. A BOC Doppler defect was used since it produces the least amount of negative reactivity feedback to mitigate the transfent. The Tech. Spec. most positive moderator temperature coefficient of +0.5X10 hp/ F was used because a positive MTC 207

results in positive reactivity feedback and thus increases the magnitude of the power rise. kn EOC delayed neutron fraction was used in the analysis to

,produce the highest power'rise during the event.

e The HZP CE!L'Jection Event was analyzed assuming the core is initially operating at 1 l%t. At zero power, a variable overpower trip is oonservatively assumed to initiate at 25< (15' 10S uncertainty) of 2700 MMt to terminate the event.

The full and zero power cases were analyzed, assuming the value of 0.05 seconds for the total, eJection time, which is consistent with the FSAR (Reference 7).

No credit was taken for voids.

3.2.4.6.3 Results The power transient produced by a CEA eJection initiated at the HFP is shown on Figure 3.2.4.6<<1. Results for the zero power case are shown on Figure 3.2.4.6-2.

The results of the two CEA eJection cases analyzed (Table 3.2.4.6-2) show that the maximum total energy deposited during the event is less than the criteria for both clad damage (i.e., 200 oal/gm) and incipient centerline melting (i.e.,

250 cal/gm). Consequently, no fuel pin failures are predicted to occur.

3.2.4.6.4 Conclusions Since no failure of fuel is predicted to occur, site boundary doses will be limited to a small fraction of 10CRF100 guidelines and hence the consequences of this event a'e acceptable.

208

TABLE .3.2.4. 6-1 KEY PARAMETERS ASSUMED FOR THE CEA EJECTION EVENT Par ameter Units 'alue Full Power Total RCS Power (Core Thermal Paver + Pump Heat)

Core Average Linear Heat kW/ft 4. 81 Generation Rate at 2774 MWt Moderator Temperature Coeffioient x10 Ape +.5 EJected CEA Worth $ hp Delayed Neutron Fraction .o044 post EJected Radial Pover Peak 3.5

'Axial Power Peak 1. 64 5

CEA Worth at Trip $ hp Doppler Coefficient Mutliplier 0. 85 Zero Power Total RCS Pover 1.0 EJected CEA Worth ~ 60 Delayed Neutron Fraction ~ 0044 Post-EJected Radial Power Peak 7.5 Axial Pover Peak 2.15 CEA Worth at Trip -2.0 Doppler Coeffioient Multiplier o.e5 209

TABLE 3.2.4.6-2 CEA EJECTION EVENT RESULTS Full Pomr Total Average Enthalpy of Hottest Fuel Pellet 154. 1 (cal/gm)

Total Centerline Enthalpy of Hottest Fuel 238 8 Pellet (cal/gm)

Fraction of Rods that Suffer Clad Damage (Average Enthalpy > 200 cal/gm)

Fraction of Fuel Having at Least Incipient Centerline Melting (Centerline Enthalphy >

250 cal/gm)

. Fraction of Fuel Having a Fully Molten Centerline Condition (Centerline Enthalphy > 310 cal/gm)

Zero Power Total Average Enthalpy of Hottest Fuel Pellet 105. 8 (cal/gm)

Total Centerline Enthalpy of Hottest Fuel 156. 7 Pellet (cal/gm)

Fraction of Rods that Suffer Clad Damage

.(Average Enthalpy > 200 cal/gm)

Fraction of Fuel Having at Least Incipient Centerline Melting (Centerline Enthalphy >

250 cal/gm)

Fraction of Fuel Having a Fully Molten Centerline 0, ~

Condition (Centerline Enthalpy > 310 cal/gm) 210.

0 2 3 TIl'K, SE(PKS FLORIDA R h LIGHT CO s EfRUL ELEj'BA'SSBSLY EJECTIN BElT FIHJP St. Lucre KlK PO!ER TIK Power Plant 2'ar YS 3.2.0.6-1 211

2ER0 PO'ER 0

FLOR 1DA POWfR L.LlGHT COI GÃML ELBBA ASSPBLY EJECI'II 8/ENT St. Lucre 2 C0IK P9'ER VS TIPE Nuclear Power Plant 212

3.2. 5 Il~a.M~S ID PM~CTOR CCOIQ~ HwTBI ZIiVE.".JTOFY 3.2. 5. 1 CVCS EQUIP;JCTIO:3 FAK UFZ~K LR'L CO~PFOL Q TB'. (PICS'V I'

a ~

aJLI I ~ S v v " al

~, I a ~ I vA t', ~

TFZ EFO 'i Kv TI N

.2.5.1.1 Identi ication of Causes A VCS malfunction that produces an unplanned increase in reactor coolan system inventory may be caused by a failure in the pressurizer level trarmitter which causes an erroneous 3ow-low level signaL. %e genera+ed signal will be trmsmitted to the controller which responds by actuating t'h e second charging pump and closing the letdown fLow control valve to i+s m'nt .um flow position he single failure considered was the carplete closing o +he le+0en control valve which occurs concurrently with the start-up of the second chargir~~ ~p.

The effect of this sirgle failure is to increase the RCS inventory at e~fester rate.

The CVCS mal+3ection is assumed to occur without,inc. easing or di"u+ing +he primary coolant initial boron concentration. The case of,a CVCS malfundtion th-"t produces a boron dilu+ion is presented in Section .2.4.4..

3.2.5.1.2 An~& sis o 1 fects and Conse uen"es Table .2.5.1-1 lists the assumptions sad initi~~ conditions used for t¹is anQysis. Additional clarification to the assznptiors hnd parmneters lis.ed in Table 3.2.5.1-1 is provided es olloir:

A high core power erA high core inlet tenp rature ms chosen to amimize the thermal expansion of the charging fluid. Since the charging flow t..rough the regenera+ive heat exchanger exceeds the letdmm flow, .he temperate of +he ma'<eup water, added to the RCS by the charging pumps is decreased. There ore, the most neg tive echnical Specification value o fi..C was selected to maximize the positive reactivity addition from, injection o cold makeup water.

The mmimum charging fLow due to the operetion of tm charging pzaps is B" gpss. The net flow increase to the RCS is 84 gpn, considering the 4 gpm for the control Meed tab.'off.

$ .2.5.1. ~~ Pasults Table 3.2.5.1-2 presents a chronological sequence of events which occur during a PICS mal unction (in combination with closure, of the letdown control valve +o the zero flow position) from the init'ial malfunction'ntil the op-.rat or stablizes the plant. Th'e dynamic response of th. NH S power, heat flux, P,""

temperatures, RCS pressure and pressurizer liquid volte is- presented in Figures .2.5. 1-1 to 3.2.5-1 Milure of the Pressurizer Level Control +stem causes an increase in reac;or coolant system inventory and pressure initiated by the start-up of +he second cMrging pump coupled with the termin".tion of letdov~x Q.ow. Ke increasi~

pressurizer pressure activates the proportional sprays which slow the pressure increase by condensing steam in the pressurizer. The increasing pressuriz r pressure eventually activates all of the proportional spry.

213

he addition of water to the RCS by charging increases the pressurizer liquid vo'ere and hence raises the water level in the pressmizer. Brentuel"y the pressurizer water level will reach the high level alam setpoint which is set at g& ft . Ke rate of fi'ling is slow enough .hat operator ection to

', terminate the charging letdown flow imbalance in 20 minutes . rom the time the hi+ level alarm occurs is suf icient to prevent filling of +he pressurizer.

..2.5.1.4 Conclusion The operator M~ 20 minutes available after the high pressurizer leve1 e~~m occurs to prevent fil"ing of the pressurizer. his is sufficient time for +he opera. or to terminate the charging-letdown flow inb "ance. 'herefore, acceptance criterion regarding an accep+able period of time for operator action is met.

214

KEY PARPJ~EP.. A ~Q~~ FOF. '2E PICH IKL~vJl!CTIVv H~'.

J A 4 ~ iCL a~4 I s e Ia ~ ~ ~ L

~ '4 at Parameter L'sits Value otal KH Power (Core hermal Power +

Pump Qg~+ )

Initial Core Coolan+ 552 Inlet Tmp-rature Eni ial Reactor Coolant psia System Pressu e Doppler Coefficient NQ+iplier 1.15 Yaderator emperature Coefficient 10++ F 215

5 SEQUENCE OF EVENTS FOR THE PLCS MALFUNCTION EVENT WITH h SIMULTANEOUS CLOSURE OF THE LETDOWN CONTROL VALVE TO THE ZERO FLOW POSITION Time (tee) Event Set int or Value Charging Floe Maximixyd and 930. 0 Letdown Floe Lost; As Pressurizer Water Vol+ac High Pressurixeg Level Alarm 980. 0 Annunoiates, f't~ Pressurixer Water Vol+ac 1377 Operator Turns Off'harging 1412. 7 Pumps and Opens thy Letdown Control Valves; ft~ Pressure xer Mater Volume 216

20 0

FLORIDA R 4 LIGHT COe CVCS MALFUNCTION (EXCESSIVE CHARGING) EVENT St. Lucre 2 Power P1ant

'Nuclear

. CORE PGMER VS .TiME 217

0 0 552 E?8 TIE, SEGm FLORIDA POKER > LIGHT COe CVCS NLFUNCTION (EXCESSIVE t;HARGING) EVENT. FIGURE St. Lucio 2 Ruc1ear Pomr P1ant CORE HEAT. FLUX.VS TINE 3,2,5,1-2 218

OUTLET AVERAGE I.

INLET 552 8N TIE, SECS'K FLORIDA ER 5 LiGHT COe . CVCS NLFUNCTION (EXCESSIVE CHARGING) EVENT. FIGURE St. Lucre 2 c1ear Power P1ant REACTOR COOLANT SYSTEM TEMPERATURES VS TIME 3,2,5.1-3 219

2415 I

K 245 2391 FLOR! DA:

h J.lGHT COe

'OWER

. CVCS'LFUNCTION .(EXCESSIVE CHARGING) EVENT St.,Lmcfe 2'

'uc1ear Power P1ant REACTOR COOLANT SYSTPl PRESSURE VS TIME 220

2 3300 g 3200 ZN I 0 276 FLORIDA R ~ LIGHT COe CYCS NLFUNCTION (EXCESSIVE CHARGING) EVENT St. Lucre 2 ~ ~ FIGURE Ruc ear Power P1ant PRESSURIZER LIQUID VOLUME VS TINE 3,2,5,1-5 221

-3,2,5 2 INADVERTENT OPERATION OF IBE ECCS DURING POWER OPERATION Inadvertent operation of the ECCS during power operation (Mode 1) is caused by a malfunction Mich results in startup of the safety i+ection actuation pumps such as an inadvertent Safety Infection Actuation Signal. This event ms not analyzed for Cycle 2 since the shutoff head of the i+ection pumps is much less than the RCS pressure in Mode 1. The impact of initiation of charging floe upon SIAS signal is the sane as the CVCS malfunction event analyzed, in Section 32,51 ~

0" 222

.2.6 DEC~+~ IK REACTOR COGLAT,i PYHTB'.- Il:VZI QPY 3.2.5.1 KZS"URI"W ER~>KFZ IECRZg~E ~I P: INAD~R~~ OP.. ~-r OP 3.2.6.1.1 Identification of Causes Ke Inadvertent Opening of the Power Operated Relic Valves (PORVs) Ever,+,

initiated at rated thecal power is ono of the DBR analyzed to deternin a

~

bias factor . used in establishing the "herma3 fhrgin!Low Pressure ( .!/LP) se+points. This bias factor (floor), along with conservative tmp reture, pressure, and power input signals assures that the H/LP trip preven+s the D?::R from dropping below the MDL limit. Hence, this event was analyzed for Cycle 2 to generate the bias factor to be included in the L'!/LP setpoints. his is consistent with C-~ methodoloigy stated in Reference 2. An addition.".1 per ormed in combination with a Ioss of Cffsite Power to prov.-".e ana1ysi='m estimate of the number of potential fuel failures for radiological dose calculations. This latter ana1ysis is presented here.

¹ inadvertent opening of the KBVs on the pressurizer could be caus " by either a passive mech'.ical failure o the v ~ve, a spurious ele trical signa',

or an operator error.

The inadvertent opening of the PORVs results in s Reactor Coolant Q'st (RCS) inventory decrease and a decrease in the RCS pressure. The depressu iz tion of the RCH can cause the fue" +o approach the D'HR MZIs <Di~~R = 1.2B b3sed on C 1 correlation) ~ The actions of the 2~i/IF trip prevents the SAPuw~ from being exceeded. Since no fuel pin failures &e predicted to occur, si+e boundary dose criteria in the 10CFR1X guidelines are not approach'.

3.2.6.1.2 Analysis of sects and Conse uences The wadvertent Opo.ning of +he KRVs Event {with a. concurrent Ioss of Of si+e Power (LOAC)) ms determined to be the limiting pressurizer pressure decreas even+. Therefore, this even+ is presen+ed.

Following the inadvertent opening of the KKVs, reac.,or pressure be~ ..s to decrease while core Q.rr and power rerain essentia>>1~v constant. 7".:-R degradation is terminated soon a ter reactor trip.

A reactor trip signal is generated by the ~!/LP. This analysis orly cre6its the action of the floor of the Pi/IF trip fmction. The LOAC caus s the reactor coolant pumps '+o coastdom and both main feedw..ter pcs "ose pow end ".

begin to coastdown.

Due to the loss of main feedwater flow, the st(~~ generator pressure incre~ses to the main steam safety valve (NMV) opening se+point. The steam gener".or inventory dissipates RCS heat until auxi'iary fee9wa+er is autcvatic."-.Ily initiated on low steam generator water level. A ter 1800 seconds, the op rator is assumed to te3.e control and uses the atmosheric dump valves (ADVs) to cool the plant to the point that shutdown cooling can be initiated.

223

.2.6.1.'5 Results Table ".2.5.1-1 lists the ini+ial conditiors asazned in the analys.'s. I~imuz core power, inlet temperature, RCD pressure and minimum core flow rate was chosen to minimiz DK~R. Ke f1oor of +he 21/LP low pressuriz.r pressure tr 'p is assumed to be in the manu~~ mode with the valves closed causing by~

setpoint was conservative" y assumed to be 179o psia. The steam dm.p and system stezg to exit via the main steam safety valves during RCH cooldown.

A sequence of events f'r the Inadvertent Opening of the PORVs Even+ !with concurrent IOAC ) is given in Table ~.2.6.1-2. Figures 3.2.6.1-1 through

$ .2.6.1-5 show the ÃSCS response or pow r, heat flux, PCS tempera.ures, RCC pressure, steam generator pressure (representative both steam generators) and reactivities.

Pate ninimum transien+ D?SR was 1.~2 which is greeter than .he 1.29 DI R "<<ZDL limit, thus no fuel f'ailure is predicted to oc u..

T¹ total amount of steam released to the atmosphere during +his event is less than that for the Loss o Of site Power vent. The radiolcbrical consequen" s of the operir~ o the PORVs will therefore be bounded by the results o the

.Loss of Offsite Power Event.

3.2.6.1.4 mnclusions

=

5he radiolog c::1 releases f'r the ~wa8vertent Opening of Relief Valves with a Loss of Offsite Power, vent. are well within t¹ Power Cp rated

+he guide'ines of 10CFR1CO. Ito fuel pins are predicted to fail.

0 224

TAMIL~ r.2.6.1-1 1EY PARIES ~~"= AHERN FCR;JK Ihf."'F" HP

'E! htL ' \ I

~ ~ I ~ J saw lg ~ ~ ~

Parameter Unite Value Total RCB Power 2774 (Core Therm~& Power +

Pump Hea+) .

~mitial Core Coolant ~~et 552 Tenperature Initi<~ rC -

Pressure Ps la Z'6" l~h"erator empcrture Co ficient 10~+ F -2. 7 CM North at Trip -5.5 225

TABLE 3e2e6 ~ 1 2 SEQUENCE OF EVENTS FOR THE INADVERTENT OPENING OF THE PRESSURIZER POWER OPERATED RELIEF VALVES EVENT Time (scc) Event Set int or Value 0 0 Inadvertent Opening of Both Pressurizer PORVs 21.6 TM/LP Trip on Low Pressurizer 1799 psia Pressure 22.8 CEAs Begin to Enter Core:

Turbine Trip on Loss of-Power to CEDM Power Supply Buses 23.2 Time of Minimum DNBR 1e32 24.8 Loss of Offsite Power: Reactor Coolant Pumps Begin to Coastdown 26.2 Main Steam Safety Valves Open 990 psia 29 ~ 6 SIAS Setpoint 1648 psia 59.6 HPSI Pumps Reach Full Speed 226

FLOR I DA INNMERHÃ MlI% V R 5 LIGHT CO St. Lucre 2 Nuclear Power Plant e

~ PRESSURIZER Pgr+ (fggtED RELIEF Vgh ES Pgfj ONE PSER  % TIPE 227

I 0

0 19l j20 TIK. SECQ'tDS INAP/ERIBtT 0%HIN6 V FICAJfP PQHER 4 st.

LIGHT Luc)e 2 Powe~

CO<

Plaht

'tHE PKSRIRI2ER PO& ~K) IBJEF VAL~tES '5,2,R,3.-'?

mK fKAT FLljX US BC'uc1ear TIIE'28

OWLET

'VERAGE INLET

't ~

60 FLOR IDA INA9/ERtBlT 9BlING (F R 4 LIGHT CO St. Lucre 2 e

'K PKBJRI2ER RNER (RRK) REF VALUES Power Plant

'hclear NOLNT M)TH"l TBKRATURES VS 8/BA'KTOR TII'F 229'

20 FLORIDA POWER E LIGHT 'COo . IN~em OPE.lIrm ~

St. Luc)e 2 'tHE PRESSURIZER PS& APEPATED RELIEF VALVES BPlT Nuclear Power Plant PFACfQR (NLW SYSTEN PPESSlBE VS TPE 230

0 19/

TItK, SEVNDS FLOR I DA ER I Lucre LIGHT CO e INAV/ERIBfl OPBII% lF St. 2 TfK PRESSURIZER RKR (%RATED REUEF VALYES 8/BlT Nuclear Power Plant STEN GBEPATOR PRESSURE VS TIl'K 231

3 2,6,2 SHALL PRIMARY LINE BREAK OUTSIDE CONTAINMENT 3.2.6.2.1 Identiffcation af Causes ~

.The Small Primary Line Break Outside Containment Event was analyzed to ensure that the resulting site boundary doses are within the guidelines o!'0CFR100.

A Small Primary Line Break Outside Containment Event may r esult from a brcak in a leMown line, instnmcnt Ifne, or ssnple line. Thc double ended brcak of the letdown line outside containment upstream o!'he outside contafnment isolation valve was selected for this analysis since ft fs the largest line and results in the largest release of reactor coolant to the envfranment.

3 2.6.2.2 Anal is o!'f!'ccts and Conse uences t

The Small Primary Line Break Outside Containment Event was initiated from the conditions presented fn Table 3.2.6.2-1. The assanpt fons  !'r radialogical release oalculations are given in Table 3.2.0-8. These conditions and f

assuapt fons were selected to maximize the rad ologicel rcl case. Initf al prfmary coolant activity was assumed to be at the technical specification maximum of 1 uCf/gm. An fadine activity spike coinoident with rapid reacto~

coolant system depressurfzation was assumed to occur upon reactor trip or the pressurizer emptying, whichever occurred sooner. An iodine activity spiking factor of 500 was used. To maximize the leak rate from the letdown linc, critical flow from the break was assumed.

To further ensure canservatfve results, a ten minute delay fn the automatic olosing of the leMown fsolatfan valve upon Safety In)ection Actuation Signal (SIAS) was assumed in the dose calculations. This assumption, fn con5unction with using the largest break size, results fn more adverse doses than those obtained usfng smaller break sizes.

The single active failure . of an isolation valve was considered in the analysis. The leMown line fncludes two isolation valves fn serfes situated inside contafnment. Hence, !'af lure of one isolation valve does not make the consequences of the event more adverse.

3 2 6.2,3 Results Letdown flow is relcascd il to thc aux far y building resulting in slowly decreasing RCS pressure and pressurizer level. Activity escaping to the auxiliary building is vented to atmosphere. A reactor trip on low pressurizer pressure occurs at 936.5 seconds. The SIAS and letdown linc isolation occurs at 972.5 seconds. Dose calculations assumed this valve did not shut until 1572. 5 seconds, maximizing the activity release af ter coaancncemcnt o!'he iodine spike. At 1800 seconds, thc operator is assumed to inftfatc plant coaldown usf ng the atmospherfc dump valves, resulting in fur ther r elease of activity.

The resultant doses to the exclusion area boundary and to the low population zone are gfven below.

232

Exclusion Area Low Population Zone Bound sr (2-hr) (8-hr)

Thyroid:

Nole Body 200 aREH The total release of reactor coolant is less than 82,000 ibm.

~

Table 3.2.6.2-2 presents the sequence of events for the mall pr fmary line

, break outsfde containment. F fgures 3.2.6.2-1 to 3.2.6.2-4 shoe the HSSS response for poser, heat flux, RCS temperature and RCS pressure.

3.2.6.2.4 Conclusions The results of a Small Primary Line Break Outside Containment Event shoe that t the radiological consequences are, a fraction of the 10CFR100 guidelines.

233

TABLE 3 2 6.2>>1 KEY PARAMETERS ASSUMED FOR THE SMALL PRIMARY LINE BREAK OUTSIDE CONTAINMENT EVENT Parameter Vt its Vtltt Total RCS Power (Core Thermal Poser

+ Pump Heat)

Initial Core Coolant Inlet Temperature Initial Reactor Coolant ysia 2¹10 System Pressur e Initial RCS Vessel 363, 000 Floe Rate CEA cnorth at Trip S4p -5.0 234

TABLE 3.2.6 2M SE ENCE OF EVENTS FOR THE SHALL PRIMARY LINE BREAK OUTSIDE CONTAINMENT Event Set int or Value, 0 0 Letdown Line Break Occurs

, 936.5 Low Pressurixer Pressure Trip 1820'sia Signal Generated 937.7 Trip Breakers Open 938. 0 CEAs Begin to Drop in the Core Zodine Activity Spike Begins 945.3 Secondary Safety Valves Open 1000 psia 972. 5 Safety Infection Actuation Signal 1578 psia L'etdom Line Isolation Valves Begin to Close 1002. 5 Safety Infection Pumps Reach Full Speed 1800. Operator Borates to Cold Shutdown Concentration, and Commences Cooldown Using Atmospheric Dump Valves 235

80 g 7O 60 p 50 0 200 Q3 600 KO lm 3293 1<6) 188 1XO PK TIrC, SEmtDS FLORIDA POWER 5 LIGHT COe El10'5 UiK BPFN BBtT FIRPE St. Luck e 2 TIf'E Nuclear Power Plant G3RE P%KR YS 5,2,6,2-1 236

0 FLORIDA P ER < LIGHT COe LEEM LItt BfM 8/BJT FINK St. Lucre 2 . CO% HE'AT FUN % TIPE 3,2,6,2-2 ear Power Plant 237

AVERAGE 0 200 CH 600 KO 1000 32% 1N) 1600 ~1 2fm TI%, SEVftDS FLORIDA PONER < LIGHT COe LEEOJH LII'K BEK EVW FIBNE St. Lucre 2 Power P1ant

'uc1ear fBCtoR CHLOE SEP1 1PPEMNB 4 TItK 3,2.6,2-238

0 ZO 45600 800 Z00 3293 3NH 1600 M3 2m TI%, SE(RES FLOR IDA POWER 5 LIGHT CO e 'LEERED UNE SEW BBtT FIHJPE SC. lucfe Power Plant 2'ar KAClt3R OXjLA"tT QSlP PKRfK US TIfE 3,2.6.24 239

3,2 6,3 STEAM GENERATOR TUBE RUPTURE WITH A CONCURRENT LOSS OF OFFSITE POWER

-.. 3.2.6.3.1. Identification of'auses The Steam Generator Tube Rupture (SGTR) Event was analyzed to assure that the dose criteria'f 10CFR100 are not exceeded.

h SGTR is assumed to occur as a result of a double-ended rupture of one of the U-tubes present in the steam generators. Additionally, a Loss -

of AC Power (LOAC) concurrent with reactor trip increases the radiological releases to the envir onment.

3.2.6.3.2 Anal sis of Effects and Conse uences The SGTR Event was analyzed assuming the initial conditions in Table 3.2.6.3-1.

In addition, the following assumptions were made:

a..While the reactor is oper ating at full power pr ior to trip, the stedn mixture containing reactor coolant fission products passes through the turbine and the condenser.

b. Following the reactor and turbine trip, all fission product activity that is released is via the Main Steam, Safety Valves (MSSV) until operator action at 1800 seconds.

c. Thirty minutes (1800 sec) after the tube rupture occurs, the operator identifies the problem 'and isolates the af'iected steam generator. ht this time, plant cooldown is initiated using the unaffected steam generator ADV's.

This analysis also assumes that f'ollowing the SGTR, the RCS pressure drops until reaching the floor of the TM/LP low pressurizer pressure trip setpoint.

Earlier trip functions are not credited. Offsite power is assumed to be lost

'at time of trip. The RCS continues to depressurize and the pressurizer empties.

Subsequent to reactor trip, stored and f'ission product decay heat is dissipated by the reactor coolant and main steam systems. In the absence of'orced reactor coolant flow (due to LOAC), convective heat tr ansf'er is supported by natural circulation. The increasing steam generator pressure results in steam release to atmosphere via the MSSVs. ht 1800 sec the operators are assumed to isolate the affected steam generator and initiate plant cooldown through the unaffected steam generator atmospher ic dump valves. With the availability of stand-by power, emergency feedwater is automatically initiated on a low steam generator water level signal. This analysis conservatively assumes that emergency feedwater will be unavailable until 1800 seconds and normal feedwater flow ramps down immediately following loss of offsite power.

3.2.6.3.3 Results Table 3.2.6.3-3 contains the sequence of events for the hot full power SGTR Event with Loss of AC Power. Figures 3.2.6.3-1 through 3.2.6.3-5 show the NSSS response for core power, core heat flux, RCS temperatures and pressure, and steam generator pressure.

240

The tube rupture causes the RCS pressure to decrease. Concurrently, the liquid level in thc affected steam generator increases. At approximately 877. seconds, into the event, a reactor trip is initiated by the TM/LP lov pressurizer pressure trip setpoint of'820 psia. The trip initates a turbine/generator trip and an assumed concurrent loss oi AC power.

Following reactor trip', RCS pressure decreases rapidly, and the pressurizer empties at 886.9 seconds due to thc continued primary to secondary leak. After the pressurizer empties, the reactor vessel's upper head becomes thermal-hydraulically decoupled from the RCS system. Due to f'lashing oaused by the deprcssurization and . boiloff (irom the metal structure to coolant heat transfer), voids f'orm in this region at about 8&9 seconds. '

Safety Infection Actuation Signal (SIAS) is generated at 887.4 seconds on lov pressurizer pressure. The High Pressure Safety In)ection (HPSI) pumps deliver fluid to the RCS at approximately 1340 seconds, and the upper head voids begin to collapse

'-:at approximately 1500 seconds.

Following turbine trip and the loss of of'fsite paver, the main stcam system pressure increases until the MSSVs open at 883.1 seconds ~ A maximum secondar) pressure of 1000 psia occurs at 886.8 seconds. Subsequent to the peak in pressure, the steam generator "pressure decreases, and the MSSVs cycle (open/close) to maintain the secondary pressure.

At 1800 seconds, the operator identifies and isolates the affected steam generator by closing the main steam isolation valves. The operator proceeds to .

cooldown thc system. by means of the atmospheric dump valves and emergency feedwater flow to,the unaffected stcam generator. After the prcssure and temperature are reduced to 175 -psia and 300 F, respectively, the operator activates the shutdown cooling system and isolates the unaffected steam generator.

Throughout the transient, the maximum RCS and secondary pressures do not exceed the 110% of design pressures, ensuring the integrity of the RCS and the main steam system.

At 1800 seconds, when operator action is assumed, no more than 68,823 ibm of stcam from the affected steam generator and 67,535 Ibm from the unaffected steam generator are discharged via the main steam safety valves. During the same period of time, approximately 69,083 lbms of primary coolant has leaked into the damaged steam generator .

operator begins plant cooldown at the technical specification cooldown I'he rate cof 75 0 F/hr using the intact steam generator's atmospheric dump valves, and

""the emergency fecdwater system. For the 1800 seconds to tvo hour (7200 sec) cooldown period, approximately 095,000 ibm of steam are released to the environment through thc atmospheric dump valves. An additional 1,080,000 ibm oi stcam are released for the tvo to eight hour cooldown.

Table 3.2.6.3-2 presents thc radiological doses for the SGTR Event and demonstrates that the site boundary doses are well within the 10CFR100 limits.

241 0'

3 2 6.3.0 Conolusions The radiological releases oalculated for the SGTR Event with a concurrent Loss of Offsite Power are:

(1) with an asiumed preacoident iodine spike in the reactor coolant and with the highest worth control rod assumed to stiok in the fully withdrawn position on scram, the calculated doses do not exoeed the values of 10CFR100, and (2) with an equilibrium iodine concentr ation oorresponding to full power operation and an assumed aocident generated iodine spike, the calculated doses do not exceed 10$ of 10CFR100.

Secondary system pressures are well below upset pressure limits, thus, assuring the integrity of these systems.

242

TABLE 3e2 6 ' 1 KEY PARAMETERS ASSUMED FOR THE STEAM GENERATOR TUBE RUPTURE EVENT WITH A LOSS OF OFFSITE POWER Parameter Uufta Value Total RCS Parer NMt

'774 (Core Thermal Pmer

+ Pump Heat)

Initial Core Coolant OF

, Inlet Temperature Initial RCS Vessel 363,000 Flue Rate Initial Steam Generator'ressure psia 805 Steam Generator U-Tube Break Size in2 0,336 CEA Worth at Trip H.5 Initial Reactor Coolant. psia 2400 System Pressure 243

TABLE 3.2,6.3-2 ~

RADIOLOGICAL EXPOSURES AS A RESULT OF A STEhM GENERATOR TUBE RUPTURE EVENT WITH A LOSS OF AC Paraaeter DOSE (REM)

LPZ Thyroid PIS 2,0 0 F 48 GIS le92 7 e 7'5 Mhole Body 0 '3 0.06 244

TABLE 3.2.6 3-3 SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE EVENT Analysis Setpoint of Value Time (sec) Event ~(nit)

OeO Tube Rupture Occurs 877.3 Reactor Trip Signal on Floor 1820 of TM/LP 878 75 CEA's Begin to Drop 883 ~ 1 MSSV's Opene 988 886.8 Maximum S. G. Pressure 1000 886 ' Pr essurizer Empties 887.4 SIAS Generated on Low Pressurizer 1578 Pressure 917.4 HPSI Pumps Reach Full Speed 1800,0 1~ Operator Borates to Cold Shut-dcwa Concentration

2. Operator Isolates Affected S. G.

by Closing MSIV

3. Operator hctivates ADVs (Unaffected S. G.) to Commence Cooldown of RCS

0. MSSVs Close

+MSSV Cycle Until Operator Activates ADV's le 1800 Sec 245

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1ear Power P1ant RE'ACTOR OmLAW'YSTEN PfESURE VS TPK 249

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3 2,7 MISCELLANEOUS 3.2.7.1 As etric .Steam Generator Events 3.2 7.1.'1 Identification of Causes The transients resulting from the malfunction of one steam generator are analyzed to determine the initial margins that must be maintained by the LCO's such that in con)unction with the, RPS (asymmetric steam generator pressure trip) the DNBR and Fuel to Centerline Melt (CTM) design limits are not exceeded.

The four events which affect a single generator are identified below:

e) Loss of Load to One Steam Generator (LL/1SG) b) Excess Load to One Steam Generator (EL/tSG) c) Loss of'eedwater to One Steam Generator (LF/tSG) d) Excess Feedwater to One Steam Generator (EF/1SG)

Of the four events described above, it has been determined that the Loss of Load to One Steam Generator (LL/1SG) Event is the limiting asyaaaetric event.

Hence, only the results of this transient are reported.

The event is initiated by the inadvertent closure of' Single Main Steam Isolation Valve (MSIV), which results in a loss. of load to the affected steam generator. Upon the loss of load to the single steam generator, its pressure and temperature increase to the opening pressur e of the secondary safety valves and its level decreases. The core inlet temperature of the loop with the affected steam generator increases resulting in an asymmetric temperature across the core. The intact steam generator <<picks up" the lost load, which tilt causes its temperature and pressure to decrease, and its level to increase, thus causing the core average inlet temperature to decrease and enhancing the asymmetry in the reactor inlet temperatures. In the presence of a negative moderator temperature coef'ficient the radial peaking increases, resulting in a condition which potentially could oause an approach to DNB and CTM limits. The Asymmetric Steam Generator Pressure Trip (ASGPT) serves as the primary means of mitigating this transient. Additional protection is provided by the steam generator level trip.

3.2.7.1.2 Anal sis of Effects and Conse uences The most negative value of the moderator temperature coefficient is assumed to maximize the calculated severity of the asymmetry.

The LL/1SG is initiated at the initial conditions presented in Table 3.2.7.1-1 and is analyzed parametric on axial shape index to determine the maximum required overpower margin (ROPM) needed to ensure the SAFDLs are not violated.

251

3.2.7.1.3 Results h reactor 'trip is generated by the Asynmetric Steam Generator Pressure Trip at 2e5 seconds based on high differential pressure between the steam generators.

1 2 Table 3.2.7.1-2 presents, the se'quence .of events for, the loss of load to one steam generator. Figures '3.2.7.1-1 to 3.2.7.1~ show the NSSS . response for core power, core heat flux, RCS temperatures, RCS pressure, and steam generator pressure The minimum transient DNBR calculated for the LL/tSG Event is greater than 1.28. s h maximum allowable initial linear heat generation rate of 18.1'kW/ft could exist as an initial condition without

. exceeding the Acceptable Fuel to Centerline Melt Limit of 22.0 kW/ft during this transient. This amount of margin is assured by setting the linear heat rate LCO based on the more limiting allowable linear heat rate for LOCA (13.0 KW/ft, see Section 3.3).

s t 3.2.7.1.4 Conclusions This event initiated from the extremes of the LCO in con)unction with the ASGPT protective trip will not lead to DNBR or centerline fuel temperatures which exceed the DNBR and CTM design limits.

252

TABLE 3.2.7.1-l KEI PARAMETERS ASSUMED FOR THE ANALYSIS OF THE LOSS OF LOAD TO ONE STEAM GENERATOR EVENT n 1 Paraaeter lltits Total RCS Pover 2720 j

.(Core Thermal Paver Pump Beat)

Znitial Core Inlet Temyerature SO9+

Znitial Reactor Coolant System Pressure yaia 2225+

Moderator Temperature Coefficient x10 hp/ F M.7 Doppler Coefficient Multiplier 0 85 a) 1 For DNBR calculation, effects of uncertainties on ,these parameters vere ccebined statistically.

253

TABLE 3,2.7 ' 2 SEQUENCE OF EVENTS FOR THE LOSS OF LOAD TO ONE STEAM GENERATOR Time (sec} Event Set int or Value 0 0 Spurious closure of a single main steam isolation valve 0 0 Steam flow from unaffected steam generator increases to maintain turbine power 2.8 Safety valves open on isolated steam 1000 psia generator ASGPT+ setpoint reached (differential 222 psid pressure}

5.55 Trip Breakers Open 5.8 'ASGPT signal generates signal to Trip Turbine 5.89 CEAs begin to drop into core 6.2 Minimum DNBR occurs >1.28 7.5 Maximum steam generator pressure 1036 psia eASGPT - Asymmetric Steam Generator Pressure Trip 254

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256

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3.3 LOCA Zvents 3.3.1 Lar Break LOCA ZCCS Performance 3.3.1.1 Introduction and A large break Loss-Qf-Coolant Accident (LOCA) ZCCS performance evaluation for St. Lucie Unit 2 Cy'cle 2 presented herein demonstrates conformance with the Acceptance Criteria for Zmergency'ore Cooling Sy'stans for Light Vater Nuclear Power Reactors as presented in 1~50.46 (Reference 1). The evaluation demonstrates acceptable large break LOCA ZCCS performance for St. Lucie Unit 2 during Cycle 2 with a peak linear heat generation rate (HZGR) of 13.0 kw/ft. The method of ~sis, results and conclusions are presented in Sections 3.3.1-2, 3-3.1.3, and 3.3.1.4, respectively.

3.3.1.2 Method of sis As in the St. 'Lucie Unit 2, Cycle 1 large break LOCA ZCCS perfomance analysis (Reference 9), hereafter referred to as the reference cycle, the calculations performed for this evaluation used the NRC approved C-Z large break ZCCS performance evaluation model which is described in Refere~ 2.

Blowdown and refill/reflood hydraulics and hot rod temperature calculations were performed with the Cycle 2 fuel parameters at a core pcwer level of 2754 MVt. The blowdown hydraulic calculations were performed with the COL'ASH-4A (Reference 3) code while the refill/reflood hydraulic calculations were performed with the CSPERC-II (Reference 4) code. 9he '

hot rod clad temperature and clad exidation calculations were performed with the STRIVEN-II (Reference 5) and PARCH (Reference 8) codes. Core wide, clad oxidation calculations were also performed in this am~vis with the STRAIN-II (Reference 5) and CQQIRC (Reference 4, Suppl. 1) codes. Burnup dependent hot rod calculations were performed with PATER-3 (References 6 and 7) and STREWN-II (Reference 5) to determine the initial fuel conditions which results in the highest peak clad temperature (PCT).

Most of the ZCCS analysis inpxt parameters are the same as those of the reference cycle (Reference 9). The significant core and system parameters which differ from the reference cycle are shown in Table 3.3.1-1 ~ The major differences in this anslysis are an increased power level, reduced System flow rate, and fuel performance parameters consistent with the 18-month low leakage fuel aanaganent.

This ~sis also accounts for an assumed amount of steam generator tube plugging of up to 300 average length tubes per steam generator. Steam generator tube plugging increases system resistance to flow and hence the ability of the Reactor Coolant System (RCS) to vent steam during reflood.

The a~sis also accounts for the decreased heat transfer area and primary side coolant volume caused-by the assumed tube plugging.

As in the reference qy'cle, the worst-simile failure is the loss of one of the Low Pressure Safety Injection (LPSI) Pumps. This results in the mininnun amount of safety injection water available to the core and the maximum anount of containment spray and fans available to reduce the containment back pressure.

The contairment parameters are identical to those used in the reference cycle except that explicit purging calculations have been included which

conserva tivelyve y account for the air which may esoape through the mini-purge system. The containment parameters used for this analysis g Table 3.3.1-2.

For the b rea k spectrum described below, the results are based on an, initial core inlet temperature oi 552 0 F which is thc expected e for lant operation at full power including uncertainties. An additional analysis at full power vas performed at the minimum inlet

. temperature of 532 F for the limiting brcak size.

All possible t

break locations are considered in in a LOCA analysis. It vas demonstra e d Re fe ence 2 that ruptures in the reactor coolant pump discharge lcg location produce the highest clad temperatures. s s to the minimization of core flow for this break location. Since core flow f ti f the break size, the St. Lucie Unit 2 Cycle 2 large break calculations have been performed for the reactor coolant pump um discharge breaks for both guillotine and slot breaks over a range of brcak sizes from 5.89 ft to tvice thc flow area oi the cold leg.

3.3.1.3 Results It vas determined from this analysis that the allowable peak linear heat generation rate (PLHGR) is 13.0 kw/ft with the limiting break size identified as the 1.0 DEG/PD>> break.

At the maximum initial core inlet temperature of 552 F, which is close to the expected inlet temperature for plant operation at full power, the results are as follows. The 1.0 DEG/PD break produced the highest peak clad temperature (2041 F) and the 0;8 DEG/PD break the highest local clad oxidation percentage (13.3$ ). The 1.0 DEG/PD also resulted in the highest core vide clad oxidation which vas less than 0.55$ . The PLHGR of 3.

kw/ft is therefore demonstrated to be an acceptable limit for Cycle 2 opera on.ti Although o operation is not expected at a minimum initial core i n 1 e t t empcra turere of 532 F it has been demonstrated that r esul s conformance with 10CFR50.46 (Reference 1) at a PLHGR of 13.00 kv/ft.

The times of interest for each. of the breaks are presented in Table 3.3.'l-

3. Table 3.3.1-4 contains a summary of the peak clad temperatures and ti ox id a o n percentages for the break spectrum. Table 3.3.1-5 contains a list of the pertinent variables plotted for each break in this an y Table 3.3.1-6i. contains a list of additional parameters plotted for the limiting break (1.0 DEG/PD break) . Mass and energy release to the containment during blovdown is presented in Table 3.3.1-7 for the worst break. Also presented in this table is the steam expulsion data during Fi 3 3 1-7 shows the peak clad temperature plotted versus break size and type, demonstrating that the worst break is the 1.0 DE break. The ECCS water spillage and containment spray flow rates are presented graphically in Figure 3.3.1>>8.

Il +DEG/PD = Double-Ended Guillotine at Pump Discharge.

261

3.3. 1.4 Conclusion

'The results of the ECCS performance evaluation for St. Lucie Unit 2, Cycle.

2 demonstrated a peak clad temperature of 2041 F, a peak local clad oxidation percentage of less than 13.3$ and a peak core wide clad oxidation percentage of less than 0.55$ . The acceptance criteria for peak clad temperature, peak local clad oxidation percentage, and core wide clad oxidation percentage are 2200 F, 17.0$ and 1.0$ , respectively'. Based on these ECCS performance results, it is concluded that operation of St. Lucie Unit 2 at a core power level of 2754 MWt and a PLHGR of 13.0 kw/ft is acceptable for Cycle 2.

262

TABLE 3 ~ 3 ~ 1 St. Lucie Unit 2 Cycle 2 General System Parameters and Initial Conditions Large Break ECCS Performance Analysis Value Reference Parameters (Units) ~Cele 2 ~Cele Core Power Level 2754 2611 at 102$ oi Nominal, MWt Average Linear Heat Rate 4 ' 4.6 at 102$ of Nominal, kw/ft Peak Linear Heat Generation 13 ~ 0 13 ~ 0 Rate Hot Assembly, Hot Channel, kw/ft Peak Linear Heat Generation Rate 11 ~ 0 11 2 Hot Assembly,'vg. Channel, kw/ft Core Inlet Temperature, F 550 Core Outlet Temperature, F 603 ~ 8 597 System Flow Rate, ibm/hr 136.1x10 139 ~ 4x10 Core Flow Rate, ibm/hr 131.1x10 134 ~ 3x10 Initial G~p Conductance 1488 1262 BTU/hr<<ft - F Znitial Feet l'enter1ine 3283 3286 Temperature , F initial Fuel )verage 2092 2134 Temperature , F Znitial lg , RcdpsiaGaa 1121 990 Pressure Hot Rod Burnup, l%D/MTU 1000 620 No. of Plugged Steam Generator. 300 Tubes per S.G.

(1) System flow rate consistent with 363,000 gpm.

(2) Conditions are from STRIKIN-II at the indicated hot rod burnup and 13.0 kw/ft. 263

TABLE 3 ~ 3 ~ 1-2 St. Lucie Unit 2 Cycle 2 Containment Physical Parameters (The conservative direction with respect to minimum ECCS containment back-pressure appears in parentheses.)

Net Free Volume (Maximum) 2.506 x 10 ft3 Containment Initial. Conditions:

Humidity (Maximum) 100$

Containment Temperature (Minimum) 60 F Enclosur e Building Temperature (Minimum) 42 F Initial Pressure (Minimum) 14.33 psia (Minimum) Initiation Times for:

Spray Flow 24 seconds Fans (3) 0.0 seconds Fan (1) 10.6 seconds Containment Spray Mater:

Temperature (Minimum) 55 F Flow Rate (Total, both pumps) (Maximum) 6990 gpm Fan Cooling Capacity (per fan)

Capacity (BTU/Sec)

Va or Tem erature ( F) (maximum) 60 0.0 120 3167 ~ 0 200 14722.0 280 27639.0 Purged Air Flow Prior to Isolation 450 ibm (max.).

5 second closure time (max.) for 8 inch mini-purge valves.

Containment Passive Heat Sinks See Tables 6.2.7 and 6.2.8 of Reference Cycle (Reference 9) 264

TABLE 3.3.1M (continued)

Heat Transfer Coefficient

h. Containment structure to enc)enure huilding atmosphere heat transfer ooefficient - 13.0 BTU/hr-ft - F.

b. Sump to base slab - 10 BTU/hr-ft - F.

c. Containment atmosphere to sump 500 BTU/hr-ft - F.

265

TABLE 3 ~ 3 ~ 1>>3 St. Lucie Unit 2 Cycle 2 Times of Interest for Large Breaks (seconds after break)

Time Hot Rod Safety Start of Safety End of Contact Rupture Injection Break In ection Tanks ~Bass Time Time Tanks Em t 1 ' DES/PD 13 ~ 5 20.6 34 ' 66.1 71. 4 0.8 DES/PD 13.6 20 ~ 8 34.5 67.0 71.6 0 ' DES/PD 14.6 22.0 35.7 69.9 72.6 1.0 DEG/PD(2) 13. 3 20 ' 34.3 62. 0 71. 3 0.8 DEG/PD 13 6 21 ~ 0 34 ' 61 ~ 8 0 ' DEG/PD 15.1 22.5 36.2 65.2 73.2 (1) DES/PD = Double-Ended Slot at Pump Discharge (2) DEG/PD = Double-Ended Guillotine at Pump Discharge 266

ThBLE 3 ~ 3 ~ 1-4 St. Lucie Unit 2 Cycle 2 Fuel Rod Performance Sunmary Large Break SPectrum Peak Core-Vide Peak Clad Local Clad Clad Break Tem erature ( F) Oxidation (S) Oxidation (%)

1 ' DES/PD 2036 <12. 96 <.54 0 8 DES/PD 2030 <12,90 5g 0~6 DES/PD 2029 <12,72 <,53 1 0 DEG/PD 2041 <13 ~ 19 <.55 0 ' DEG/PD 2040 <13 23 <.55 Oo6 DEG/PD 2032 <12 91 < ~ 53 267

St. Lucie Unit 2 Cycle 2 Variables Plotted as a Function of Time for Each Iarge Break in the Spectrum Figure Variable Desi tion Nomalized Total Core Power Pressure in Center Hot Assanb+ Node leak FLow Hot Assemb+ FLow (below hot spot) D Hot Assemb FLow (above hot spat)

Hot Assemb+ Quality Containment Pressure Mass Added to Core During Ref lood Peak Clad Temperature 268

TABLE 3 ' 1-6 St. Lucie Unit 2 Cycle 2 Additional Variables Plotted as a Function of Time for the Large Break Having the Highest Clad Temperature Figure Variable Desi nation Mid Annulus Flow Qualities Above and Below the Core Core Pressure Drop Safety InJection Tank Flow into Intact Discharge Legs Mater Level in Downcomer During Reflood Hot Spot Gap Conductance Peak Local Clad Oxidation Clad Temperature, Centerline Fuel Temperature, Average Fuel Temperature and Coolant Temperature for Hottest Node Hot Spot Heat Transfer Coefficient Containment Sump Temperature Containment Atmosphere Temperature Hot Rod Internal Gas Pressure Core Bulk Channel Flow Rate 269

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-. 337

60 000 SG COO 40 COO 3C CCC

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St. LucH 2 0.6 x DOUBLE ENDED-GUILLOTINE BREAK 5.3. 1-6H Nudoar Poser Plant IN PUMP DISCHARGE LEG 339

2200 2000 18GO

=1400 5

2 1200 1CGO 40Q 0 '100 ZOO 3GG 400 SGO 600 70 TIf1E, SECONDS FLNtlOI PEAK CLAD TEMPERATURE POWSI4 LIGHT CCL St. ~2 0.6 X DOUBLE ENDED'GUILl OTINE BREAK ntsrwmr~ ~ rr,

220 2000 1800 0 SLOT BREAKS Cl GUILLOTINE BREAKS 1600 1400 1200 0 4 . 6 8 10 12 BREAK AREA, FT2 FLORIDA 4 UQHT CO.

( Figure St. Lucio 2 PEAK CLAD TENPERATURE VERSUS BREAK AREA

~. '

30311 7 Nudeer Power Ptent

'341

I 1 TANK SPILLING DIRECTLY INTO CONTAINMENT 10000 EFFECTIVE ANNULUS SPILLAGE 12000 10000 8000 EFFECTIVE PUMP SPILLAGE 6000 0000 SPRAY FLOW 2000 0

0 80 200 320 400 TINE AFTER BREAK. SEC

.," RlNIDA Figure POWER 5 LIOHT CCL COMBINED SPILI AGE AND SPRAY INTO CONTAINMENT 3.3.1-St. Bete 2 Nudwr Power Rent 342

3.3.2 Small Break IDCA ZCCS Performance 3.3.2.1 Introduction and The 3KCS performance evaluation for the small break Icss-Of-Coolant Accident (IDCA) for St. Lucie Unit 2, Cycle 2, presented herein, demonstrates conformance with 1QCFR50.46 which presents the Acceptance Criteria for 1hiergency Core Cooling Systems (ZCCS) for Light Mater Nuclear Power Reactors (Reference 1). She evaluation demonstratee acceptable small break LOCA ZCCS performance for St. Iucie Unit 2 Cy'cle 2 vith a peak linear heat generation rate (PIHGR) of 15.0 kw/ft. 5he method of results and conclusions are presented in Sections 3.3.2.2, 3.3.2.3, and

~cia, 3.3.2.4, respective+.

3.3.2.2 Method of sis The method break IDCA of ZCCS

~sic is identical to the St. Zucie Unit 2 Cycle emQ1 performance ana~is (Reference 9),. hereafter referred to 1

as the reference cycle. Ae in the reference cycle, the calculations reported in this section vere performed using Combustion Zngineering'8 KKhpproved small break evaluation model which ie described in Reference~10.

I Zvaluation of small break IDCAs involves the use of four canputer codes.

Blowdown hydraulics are calculated using the C3KXASH-4AS (Reference 11) code.. Reflood hydraulics are calculated using the C(K?EK-II code (Reference 4). Heel rod tenrperatures and clad oxidation percentages 'are calculated using the STR13GN-II .(Reference 5) and PARCH (Reference 8) codes. Details of the interfacing of these codes are discussed in Reference 10. I~

The ZCCS an~sis assumptions are the same as those of the reference cycle (Reference 9). Aa discussed in Reference 10, the worst single failure for

~see of the small break IDCA is the failure of one of the emergency diesel generators to start. This failure results in the mininrum safety injection available to cool the core. Therefore, based on this assumption, the following injection pumps vere credited in the small break IDCA

~eisa

a. one High Pressure Safety Injection (HPSI) pump o Lo P aaue ae~Injectio (LPSI) p p

c. one charging yxrp

d. four safety injection tanks Por breaks in the pump discharge leg, it is also assumed that all safety injection flow delivered to the broken cold leg spil1a out the break. This results in the following reduced injection flow delivered to the core:

a. ~ of the flow from one HPSI pump

b. 5 of the Wow from one LPSI perp

c. 4Q of the flow from one charging pump (baaed on worst fine split)

d. 1~ of the flov from three safety injection tanlas As described in Reference 10, the amQ1 break IDCA amuses conservative+

assume that offsite power ie lost upon reactor trip. Aa a result, the safety injection pumps were assumed to await a 30 second delay (for diesel atartup and load sequencing) following a safety injection actuation signal.

343

vg The ZCCS performance an~sic considered a spectrum of cold leg breaks in the reactor coolant pump discharge leg. As demonstrated in the reference qycle anQysis, discharge'leg breaks are more limiting than other break locationy.,The break sizes analyzed include the 0.5, 0.1, 0.0375, and 0.015 ft cold leg breaks'.

Calculations vere performed using two axial shape indices.

5he most limiting small break from the spectrum vas analyzed with the more restrictive axial shape index (ASI) of -0.15 ASI units (ASIU) . The remaining small breaks of .the spectrum were analyzed vith an ASI of W.25 ASIU.

The ZCCS performance.

steam

~see accounted for the possibility of plugging generator tubes by, assuming 300 average length tubes per steam generator had been plugged. Steam generator tube plugging increases system resistance to flow and decreases steam generator heat transfer area and primary'oolant volume.

The significant general system parameters used in the small 'break calculatians vhich differ from those of the reference cycle malyeis are ~

presented in Tible 3.3.2-1 ~ Cate major differences are increased p~rer level, reduced system flow rate, and fuel performance parameters consistent with 18-month law leakage fuel management.

3.3.2.3 Results The break

~sis demonstrated',the 0.0375 ft break with a peak clad temperature of 1740oF to be the and limitirig small a peak zirconium percentage o$ less then @ll. The analysis also demonstrated that f

'xidation break sizes 0.01 5 t and smaller will not result in core uncovery.

These results are eunmarized in Table 3.3.2-2. The times at which significant events in the performance of the ZCCS occurred for each break size are listed in Table 3.3,.2-3.

The transient values of parameters which most direct+ affect fuel rod performance are shown in Figures 3.3.2-1 through 3.3.2-4 (see Tables 3.3.2-4 and 3.3.2-5). The following parameters are graphically presented for each break size:

a Eormalized Total Core Power b Inner Vessel Pressure c Break Flaw Rate d Inner Vessel Inlet Flaw Rate e Inner Vessel Two-Phase Mature Volume Hot Spot Heat Transfer Coefficient g Coolant Temperature at Hat Spot h) Hot Spot Clad Surface Temperature Figure 3.3.2-5 sunmarizes the peak clad temperature results of the spectrum ane+sis e dhe 0.0373 W break vas date ed to be the limiting mnall break. Ror breaks sma11er than 0.0373 ft core uncovers begins later vhen the fission product decay heat generation is less and, hence, the> depth of uncovery vill be less. In Sant, break sises less than 0.013 ft vig. not experience core uncovery'. For breaks greater than 0.0375 resulting system depressurization rate is faster such that the clad ft the temperature rise is terminated ear+ in the transient by Safety Injection TanIsa (SIT) actuatian.

3.3.2.4 Conclusions Reed on the results of an ana~is of a spectrum of small breaks in the cold leg at the reactor pump discharge, it can be concluded that operation cf St. lucis Unit 2 Cycle 2 at a core poser level of 2611 MWt and a HBG2 of 15.0 ft is acceptable for Cycle 2. The results of the limiting 0.0575 ft small brealc resulted in a pealr clad temperature of 17402 and a peak local clad oxidation percentage of less than Q, demonstrating the small break ZOCA ECCS performance to be less limiting than that for the large break IOCA performance results given in Section 3.3.1 ~

I ~

345

St. Iucie Unit 2 Cycle 2 General ~+stem Parameters and Initial Conditions Bnall B ea3c XCCS Performance Analysis Q Value H ference Parameter {Units) c" e 2 0rlr Core Power Ievel at 102,"~ o 2754 2611 Nminal, I6f+

Averse Line..r He~t Bate at 4.6 10'. of:Iominal, hv/ t Pee3. Linear 1Ie t Bate, la~/ft 15. 0 15. 0 Gap Conductance at P~a'z Linear 1744. 0 1514 Heat Hate, Pixel/hr-ft Z -

Fuel Center'ne Temperature a 'F5 fl'7 '7$ 5e Eh~". Linear '.hat Wte, F Fuel Average emper~ture at Peak 22 tQ Line r He. t Fate, F Hot Bod Gas Pressure, psia 1120. 6 Ho+ Hod Burnup, I1blD/!'..J {time of minimum gap conduc.ance)

I1oderator Iemperature Coefficient, hp/ F m.2x10<

Axial &ape mdex, ASIU -O. 25/-0. 15' System Floe Bate {total), ibm/hr 6 1x10 { ) 1~o. 4x1 <

Core H.ow Hate, ibm/hr 1~1 e1x1 0 1~. x106 Core M.et emperature, ~- 552 0 c:50 0 Core Cutlet Tempera+.ure, F 6"~. B COO /~

Lmr Pressurizer Pressure 1659.0 1653.0 Trip Ntpoin., psia

~~ety Injection Actuation Signal 15M. 0 =-1500.

Setpoint, psia IUgh Pr"-smre

'bad, sty Injection Pump 1214 1214 auto psi (1) -0.25 AS:g for the 0.5, 0.1, eu6 0.015 ft bred:e; 315 AS-I'U.for th-:.

0.0~75 ft bre~J.. only.

{2) System flow ra.e consistent id,th 6,00 ggn.

346

TABLE 3 '.2-2

. St. Lucie Unit 2 Cycle 2 Fuel Rod Performance Summary

~ Small Break Spectrum Peak Clad Peak Local Hot Rod Break Size Temperature Clad Oxidation Clad Oxidation (c)

(ft ) ( F) (%) (S) 0 ' ft /PD 1137 <0,009 < ~ 002 0~1 it /PD 940 <0 '03 <.001 0 ~ 0375 ft /PD( 1740 <1 ~ 92 < ~ 31 0 015 ft /PD 712 <0,001 <.001 (a) Break analyzed using ASI of -0.15 ASIU.

(b) Break analyzed using ASI of -0.25 ASIU.

(c) Hot rod oxidation values are given as a conservative indication of core-wide oxidation.

(d) PD = at Pump Discharge.

347

TABLE 3 '+2-3 St. Lucie Unit 2 Cycle 2 Times of Interest for Small Breaks (seconds after break)

Hot Spot Break Size HPSI LPSI SI Peak Clad (ft )

0 50 ft2/FD(b) 42.8 (c) 103 121. 0 0 ~ 10 ft /PD 64.0 (c) 696 710.0 0 0375 it /PD 100.0 (c) 2450. 2432.2 0 015 ft /PD( 430 ' (c) (d) 0 ~0 (a) Break analyzed using ASI of -0.15 ASIU.

(b) Break anayzed using ASI of -0.25 ASIU.

(c) Calculation terminated before time of LPSI pump activation.

(d) Calculation terminated before initiation of SI tank discharge.

34S

TABLE 3.3.2W St. Lucie Unit 2 Cycle 2 Small Break Spectrum Break Size and Location Abbreviation ~F1 ures 0 5 ft Break in P p( )

Discharge Leg 0' ft /PD 3.3.2-1 0.1 ft Break in Pump( )

Discharge Leg 0~1 ft /PD 3 ~ 3e2 2 0.0375 ft Break in Pump Discharge Leg 0 '375 ft /PD 3 'e2 3 0.015 ft Br eak in Pump Discharge Leg 0.015 ft /PD 3.3.2~

(a) Break analyzed using ASI of -0.15 ASIU.

(b) Break analyzed using ASI of -0.25 ASIU.

349

TABLE 3 ~ 3 2H St. Lucie Unit 2 Cycle 2 Variables Plotted as a Function of Time for Each Small Break in the Spectrum Figure Variable Normalized Total Core Power Inner Vessel Pressure B Break Flow Rate Inner Vessel Inlet Flow Rate Inner Vessel Two-Phase Mixture Volume Heat Transfer Coefficient at Hot Spot Coolant Temperature at Hot Spot Hot Spot Clad Surface Temperature H

<<Refer to figures 3.3.2-1A through 3.3.2-4H.

350

1.50 pC LLJ CD 1,00 LU CD I

CD .75 t

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.25 30 60 90 120 150 TINE, SEC FLORIDA CORE POWER Figure POWER 4 UQHT CO.

St. Lucio 2 0,5'T 3.3.2-1A BREAK IN PUMP DISCHARGE LEG 351

2400 2000 1600 1200 800 400' 0 50 60 90 120 150 TINE, SEC FIBIDA FigUf8 POSER 4 UGHT CO. INNER VESSEL PRESSURE St. Lucte 2 3.3.2-1B Nude'ower Ptant 0,5 FT BREN IN PUNP DISCHARGE LEG 352

9000 7500 6000 4500 CD LI 3000 1500 0

0 30 90 120 150 TINE, SEC FMRIM 'Figure POWER 4 UGHT CO. BREAK FLOH RATE St. Lucio 2 3,3.2-1C 0,5 8 BREAK IN PUNP DISCHARGE LEG 353

140000 32000 20000 16000 CD U

8000

-8000 50 60 90 120 150 TIME, SEC FLORIDA POWER 4 LIGHT CO.

Fig4f8 INNER VESSEL INLET FLOW RATE St. Uric 2 31312 Nudear Power Rant 0 5 FT BREAK IN PUMP DISCHARGE LEG 354

3600 3000 21100 UJ 1800 CD 'tQP OF CORE 1200 600 0

0 .30 60 90 120 150 TIME, SEC fNRIDA Figure paweR a uam CO. 'NNER"VESSEL TWO-PHASE MIXTURE VOLUME St. Lucla 2 'FT 3.3.2-1E Poser Rant 0,5 BREAK- IN PUMP DISCHARGE LEG

c~ 10,000

~ 1,000 I

UJ U

U UJ CD 100 10 1

0 90 80 120 160 200 TINE, SECONDS FLORIAA HEAT 'TRANSFER COEFFICIENT AT HOT SPOT Flgll POWEa a uaHT CO.

St. LucIe 2 0,5 FT BREAK IN PUNP DISCHARGE LEG 3.3. 2-1F Nuclear Power Rant 356

e 1200 1000 800 600 400 200 0 40 80 120 160 200 TIME, SECONDS FLDRIQA COOLANT TEMPERATURE AT HOT SPOT Figure 4 LIGHT CO.

Sf,. Lucio 2 3.3,2-1G Nuclear Power Rart 0,5 FT2 BREAK IN PUMP DISCHARGE LEG 357

1600 1000 1200 o

I 1000 800 600 400 00 80 120 160 200 TINE, SECONDS FLORIDA HOT SPOT CLAD SURFACE TB'IPERATURE FicJU POWER 4 UGHT CO.

St. Lucio 2 0,5 FT BREAK IH PUNP DISCHARGE LEG 3.3.2-1H Hucioer Power Rent 358

CC UJ CD 1,00 CL UJ CD

,75 CD

,50

.25 0

200 000 600 800 1000 TINE, SEC FMlllDA Figure.

POWER 4 IJQHT CO. CORE POMER St. Lucio 2 3.3.2-2A Pbww Rant 0,1 FT BREAK IN PUMP DISCHARGE LEG 359

2400 2000 1600 1200 800 400 200 400 600 800 1000 TINE, SEC FLQRIM Figu POWER 4 UQHT CO. INNER VESSEL PRESSURE St. Lucio 2 313 02 Nucioer Power Rant 0,1 FT2 BREAK IN PUl'1P DISCHARGE LEG 360

1200 1000 800 UJ CO CQ 600 I

C) 000 200 200 000 600 800 1000 TINE, SEC FLORIDA POWER 4 UGHT CO. BREAK FLOW RATE Recure St. Lucio 2 0 1 FT BREAK IN PUI'1P DISCHARGE LEG 3.3.2-2C 361

40000 32000 24000 UJ'/l CQ 16000 0

8000 0

-8000 0 200 400 600 800 1000 TINE, SEC FLCNIIDA INNER VESSEL INLET FLOW RATE Rgu POWER 4 UQHT CO.

St. Lucia 2 31312 Nudear Power Rant 0,1 FT2 BREAK IN PUllP DISCHARGE LEG 362

3600 3000 2000 l

UJ 1800 CD TOP OF CORE LaJ CC I

OC 1200 BOTlUM OF CORE 600 200 000 800 1000 TIME, SEC FNRIQA INNER VESSEL TMO-PHASE MIXTURE VOLUME Figure POWER 4 LIGHT CQ.

St. Lucio 2 0.1 FT BREAK IN PUI'1P DISCHARGE LEG 3.3. 2-2E 363

100,00 10,000 I 1,000 UJ IJ LL.

LU CD 100 10 200 000 600 800 1000 TIME, SECONDS FLORIDA POWER 4 LIGHT CO. HEAT TRANSFER COEFFICIENT AT HOT SPOT Ftgu St. Lwcle 2 31312 Nuclear Power Rant 0.1 FT BREAK IN PUflP DISCHARGE LEG 364

1200 1000 u 800 600 5'00 0

0 200 000 600 800 1000 TIME, SECONDS fLORIDA 4 LIGHT CO. COOLANT TEMPERATURE AT HOT SPOT Figure St. Lucio 2 3.3.2-2G MucIeer Power Pfent 0 1 FT BREAK IN PUMP DISCHARGE LEG 365

1600 1000 u 1200 O

t 1000 5

800 600 400 200 000 600 800 1000 TIME, SECONDS FUÃllDA HOT:SPOT CLAD SURFACE TPlPERATURE Flgll RAKR 4 UOHT CO.

St. Lucle 2 3.3.2-2H Nudear Power Rant 0 1 FT BREAK IN PUMP DISCHARGE LEG 366

FJ CD 1.00 UJ I .75 CD I

UJ

.50 CD

,25

'0 0 1000 2000 , 3000 9000 5000 TINE, SEC F10RIOA CORE POMER Figure

'OKER 4 LlQHT CO.

i'. Lucio 2 0.0375 FT BREAK IN PVf'IP DISCHARGE LEG 3,3.2-3A 367

2000 2000 1600 1200 800 000 1000 2000 3000 c4000 5000 TINE, SEC

"'lNlDA Figu POWER 4 IJOHT CO. INNER VESSEL PRESSURE St. Lucte 2 .0,05?5 FT BREAK IN PUNP DISCHARGE LEG 31312 Nudeer Power Rant 368

1200 1000.

800 600 000 200 0

0 1000 2000 5000 0000 5000 TINE, SEC FLORIGA Figure POWER 4 UGHT CO. BREAK FLOW RATE St. Uelo 2 3,3,2-3C 0,0575 FT BREAK IN PUNP DISCHARGE LEG 369

40000 32000 20000 16000 CO LL 8000

-8000 1000 2000 3000 4000 5000 TINE, SEC FNRIOA Ft9U powys a uGHT CO. INNER VESSEL INLET FLOW RATE St. Lucle2 Nuclear Power ~

0,0375 FT BREAK IN PUP1P DISCHARGE LEG 3.3.2 370

3600 3000 2400 QJ 1800

)

CD UJ P OF CORE I 1200 OC TTON OF CORE 600 1000 2000 3000 4000 5000 TINE, SEC FUKIOA POWER 5 LIGHT CO. INNER VESSEL TWO-PHASE MIXTURE VOLUME Figure St. Lucfe 2 3.3.2-3E 0 0375 FT BREAK IN PUNP DISCHARGE LEG Power Rant 371

100.000 I 10.000 11000 UJ CO 100 l

10 1000 2000 3000 4000 5000 TlNE. SECONDS FLORIDA Figu POWHl 4 LIGHT CO. HEAT TRANSFER COEFFICIENT AT HOT SPOT St. Lucio 2 30312 Nudeer Power Plant 0.0375 FT BREAK IN PUNP DISCHARGE. LEG 372

'200 1000 800 600 000 200 0

1000 2000 3000 0000 5000 TINE, SECONDS fLORIOA COOLANT TENPERATVRE AT KOT SPOT Figure NIOWER 4 L}GHTCo.

St Uele2 0.0375 FT BREAK IN PVNP DISCHARGE LEG 3.3.2-3G Power Ptant P

373

2200 1900 1600 D

1300 Cb 1000 700 400 0 1000 2000 3000 4000 5000 TINE, SECONDS FLORIDA POVfER 4 LIGHT CO. HOT SPOT CLAD SURFACE TEf'lPERATURE Figu St. Lucio 2 31312 Mudear Pew'tant 0,0375 FT BREAK IN PUI'1P DISCHARGE LEG 374

1,25 1,00

.50

.25 0

0 1QOO. 2000 3000 0000 5000 TINE, SEC FLOAlQA CORE P01IER Rgure OWER 4 UGHT CO.

't.

uciwr Lucio 2 Powec Rant 0,015 FT BREAK Iit PUNP DISCHARGE LEG 3.3.2-0A 375

2000 2000 1600 1200 SQQ 400 0 1000 2000 3000 0000 5000 TINE, SEC RlNIOA Figur POWER 4 UQHT CO. INNER YESSEL PRESSURE St. Lucio 2 3,3.2-Q 0,015 FT BREAK IN PUMP DISCHARGE LEG Nuclear Power Rant 376

1200 1000 800 600 C) 400 200 0

0 1000 2000 3000 0000 = 5000 TINE, SEC fMNIOA .

BREAK FLOH RATE Figure 4 L}OHTCO.

St. Lucio 2 0,015 FT BREAK Ill PUl'1P DISCHARGE LEG 3.3.2-LIC Power Rant 377

. 40000 32000 24000 16000 8000 0

-8000 0 1000 2000 3000 4000 -

5000 TINE, SEC

-. FLNIOA Ficju POWER 4 UGHT CO. INNER VESSEL INLET FLOH RATE St. Lucio 2 0.015 FT2 BREAK IN PUNP DISCHARGE LEG

'.3.2-4 Rucsaer Power Rant 378

3600 3000 2400 1800 TOP OF CORE CD UJ I 1200 BQTlOM OF CORE 600 0

0 ~

1000 2000 3000 4000 5000 TIME, SEC FU&lOA 4 UQHT CO. INNER VESSEL TWO-PHASE MIXTURE VOLUME Figure St. Lucia 2 0.015 FT BREAK IN PUMP DISCHARGE LEG 3,3.2-4E Nuclear Power Rant 379

3.00,000 10,000 I 1,000 LLJ

~l UJ CD 100 10 1000 2000 3000 tl000 5000 TIl'1E, SEC

~ FLOlllOA HEAT TRANSFER COEFFICIEttT AT HOT SPOT Figu POWER 4 UOHT CO.

St. Lucte 2 0,015 FT BREAK IN PUNP DISCHARGE LEG 305 2

~

Nudear Power Rant 38Q

1200 1000 800 600 400 200 0

0 1000 2000 3000 4000 5000 C

TINE, SEC FLlNIDA a uoHT CO. COOLANT TENPERATURE AT HOT SPOT Figure St. Lucio 2 0,015 FT. BREAK IN PUNP DISCHARGE LEG 3.3.2-4G Nuclear Power Plant 381

2200 1900 1600 U00 1000 700 400 1000 2000 3000 0000 5000 TII'lE, SEC FLOIllOA HOT SPOT CLAD SURFACE TENPERATURE Rgu POWER 4 UGHT CO.

St. Lucio 2 3,3.2-0 0.015 FT BREAK Ii4 PUNP DISCHARGE LEG NxSeer flaws Rant 382

1800 1600 1400 1200 1GOO 800 Q PLUMP DlSCHARGE LEG 600 400

,001 .10 1.0 BREAK AREA, FT2 IOA ER 4 LIGHT CL Figure St. Lucio 2 PEAK CLAD TENPERATURE VERSUS BREAK AREA 3.3.2-5 Nucieer Power Rant 383

3.3.3 Po'st-LOCA Lon Term Caolin ECCS Performance 3.3.3.1 Introduction and Summar Long Term Cooling (LTC) prooedures arc required to maintain the core at safe temperatures while avoiding the prceipitation of boric . aoid in the oore.

The past-LOCA LTC procedure for St. Lucie Unit 2 varies depending on the break sixe. Shutdown Cooling (SDC) is initiated if the break is suffioiently small such that successful operation is assured (RCS inventory r~stablished and hot leg temperature and RCS pressure reduced below SDC system emergency limits). However, for larger break LOCAs, simultaneous hot and cold leg indication is used to maintain core cooling and boric acid flushing. In this conservative analysis, the appropriate seleetian is based an the Reaotor Coolant System (RCS) pressure at a specified time. In actual operation, this selection can be made muoh soaner based on indications of RCS pressure, subcooling and inventory.

Figure 3.3.3-1 shows the basio sequence of events and the time schedule for "

operator actions assumed in this analysis. If the indicated RCS yressure at 23 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> has fallen below 150 psia, the break may be too large. for absolute assurance that proper suction is available for the SDC mode of operation; however, in this event, there is complete assurance that-simultaneous hot leg/cold leg infection alone will both cool the care and flush the reactor vessel indefinitely.

3.3.3.2 Method of Anal sis As in the St. Lucic Unit 2 Cycle 1 Long Term Caaling Analysis (Rcfercnce 9), hereafter referred to as 'the reference cycle, the LTC analysis far St.

Luoie Unit 2 Cycle 2 was performed using the methods documented in Reference 12, as approved by NRC in Reference 13.

r The worst single-failure assumed is the same as in the reference oycle, the failure of one emergency diesel generator. The failure of a diesel generator results in the following:

a. One HPSI jump is assumed to be operable.

b. One LPSI pump is assumed to be aperative during the short term ECCS in5eetian phase taking suction from the Refueling Mater Tank (RMT).

The pump is not used for ECCS infection after the RMT is drained because of automatic terminatian upon a Recirculation Actuation Signal.

o. Auxiliary feedwater is supplied by two motor driven pumps and one steam-driven pump. Due to the loss of one of the diesel generators, one of the two motet driven auxiliary feedwatet pumps is assumed to'e unavailable (the steam driven pump by itself has sufficient flow to remove decay heat) ~

The steam generator steam dump and RCS oooldown are assumed to begin at ane hour past-LOCA and the eooldown rate maintained at 75 F/hr until flaw is limited by the Atmospherio Dump Valves (ADVs). Additional ma5or parameters used in this performanoe evaluation are given in Tables 3.3.3-1 and 3.3.3-2, as well as the corresponding values used in the reference cyole 384

analysis. The ma)or differences accounted for in this analysis are increased power level and initial boron concentrations. To accommodate these inoreases it was necessary to from the Condensate Storage Tank.

credit a greater amount oi oondensate 3.3.3.3 Remits Figure 3.3.3-1 shows the basic sequence of events for operator aotions assumed in this analysis. The time schedule provided gives a range in which the action was assumed to occur. During the first hour operator aotion was assumed to be limited to verifying the automatic initiation of the safety in)ection and auxiliary ieedwater systems. Operator manual aotion is assumed to initiate cooldown at one hour by releasing steam from the steam generators (SG). The steam is released through the turbine bypass system (TBS), if operable, or through the ADVs, if the TBS is unavailable. The operator also manually stops or switches charging system suotion to the Refueling Mater Tank (RMT) between 1 and 1-1/2 hours post-LOCA. Stopping or switching the oharging system suction to the RWT~

~

terminates the inJection of high concentrate boric aoid from the Boric Aoid Nakeup Tanks (BAMT). Between 1-1/2 and two hours post-LOCA pressur1xer cooldown . is initiated using the pressurizer auxiliary spray system.

Between 1 and 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> past-LOCA the Safety Infection Tanks (SIT) are isolated or vented to avoid in5ecting a. large quantity of nitrogen (non-condensible) gas into the RCS. Then, at 2 to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> post-LOCA the High Pressure Safety Infection (HPSI) flow is realigned so that the total in)ection flow is divided about equally between the hot and cold legs to insure core cooling and boric acid flushing regardless of break location.

Cooldown of the RCS via the steam generator atmospheric dump system continues until the SDC entry temperature is achieved.

RCS pressure If the indicated is above 150 psia and the indicated RCS temperature is less than 325 F at 23 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> post-LOCA, the RCS is filled with liquid and there is assurance that all oonditions for entering SDC mode of operation can be established. If the indicated RCS pressure is greater than 276 psia, the HPSI pumps are throttled until indicated RCS pressure is reduced below 276 psia at which time the SDC mode can be entered. A prerequisite to throttling or terminating HPSI flow is that the system must be in a subcooled condition for the indicated RCS pressure. Therefore, while reducing RCS pressure and after shutdown cooling is initiated, essential that subcooling of the primary system, consistent with emergency it is operating procedures, be maintained.

The initiation of the simultaneous cold/hot side HPSI pump infection flow between two and six hours post-LOCA provides a substantial and increasing core flushing flow as shown on Figure 3.3.3-2. Figure 3.3.3-3 shows that with no core flushing flow, the borio acid would not begin to preoipitate until after 9.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> post-LOCA. The margin provided for the prevention of boric acid acoumulation by the net core flushing flow over the minimum flow of 10 gpm is also shown on Figure 3.3.3-3. The time at which hot leg steam entrainment of infection water is no longer a limiting faotor has. been oalculated to be less than one hour post-LOCh. Therefore, the 2 through 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> cold/hot side inJection time is initiated after hot leg entrainment has been reduoed and well before the borio aoid is predicted to precipitate.

385

3 3 '.4 Conclusions The small break LTC plan applies to those break sizes for which the RCS refills before all of the auxiliary feedwater is consumed. The small break analysis determined that, with steam generator cooldown starting at one hour post-LOCA, 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> is the minimum time required to exhaust all of the auxiliary feedwater during the cooldown and post-cooldown decay heat removal period. Therefore, between 23 and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> post-LOCA, .the operator decides .which LTC procedure is appropriate according to the RCS pressure.

At 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> past-LOCA, there is an additional hour of auxiliary feedwater supply available for continued decay heat removal. Using the plot of break area versus time to refill the RCS, Figure 2 3.3.3-4, it has been determined that for a break size as large as .030 it , the RCS will be filled at the decision time (i.e., 23 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> post>>LOCA) and, therefore, the small break LTC plan can be applied.

The LTC snalrsls also deternined that the LTC garde treat procednres can flush the core for break sizes down to .007 ft . This overlap in break sizes for which either the large or small break procedures oan be used is illustrated in tabular form in Figure 3.3.3-5. A plot oi RCS pressure versus break size after refill is shown in Figure 3.3.3A. Both figures indicate that the selected decision point pressure of 150 psia fits well within the break size range of .007 to .030 ft fdr which both large and small break procedures are applicable.

TABLE 3 3 ~ 3-1 St. Lucie Unit 2 Cycle 2 Parameters Used in the Peformance Evaluation of the LTC Plan Value Reference Parameters (Units) ~Cele 2 ~Cele Reactor Power Level 2754 2611 (102'f nominal), Wt SDC Entry Temperature, F (max) 325 332 SDC Entry Pressure, psia (max) 276 315 SG Dump Valve Capacity 15 per Valve, lb/sec min.

Auxiliary Feedwater in 276,200 150,000 Condensate Storage Tank Credited, gallons min.

Initiation of RCS Cooldown, hr.

Initial Cooldown Rate, F/hr 75 75 Post-Accident Instrument Error:

RCS Pressure, psi +100 +50 Hot Leg Temperature, F +15 +10

TABLE3 3 3 2 St. Luoie Unit 2 Cyole 2 Borio Aoid and Water Souroes tJsed in the Performanoe Evaluation of the LTC Plan The maximum possible boric acid concentration is assumed from each of these sources.

Reference

~Cele 2 ~Cele RCS 1.35 wt% 0.7 wtS RMT 1.35 wt$ 1.23 wt%

SIT 1.35 wt% 1 23 wt$

BAMT 12 0 wt$ 12.0 wtg The water inventories from each souroe are determined such that the effect of in)ection into the RCS maximizes the bor ic aoid concentration in the RCS.

RCS (maximum) 468,856 lb 468,856 lb RMT (maximum) 42325,565 lb 42325,565 lb SIT (maximum) 384,910 lb 3802952 lb BAMT>> (maximum) 157,700 lbs 157g700 lbs The following pump in)ection rates were assumed in the analysis (same as in reference cycle).

Run Out No.

Sccrce Flow Rate (GPM) Pumps Total Flow (GPM)

HPSI RWT ~ sump 552 552 LPSI RMT 2794 1 2794 CSP (via RMT, sump) 3450 1 3450 CHARGING<<<< RWT 44 3 2 TOTAL 6928 gpm

<<BAMT in)ection is terminated no later than 1-1/2 hours post-LOCA.

<<<<For conservatism, boration with three charging pumps is used in determining the boric aoid accumulation in the vessel.

388

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MC

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W M~QtWSK1W

~

~~

OffEEKHSS f ~lARft~SIJEE IHHT %XIIIII

~O~

=

EfAO. ftgOWATES ACTUATICNOOtAL CS OAE ~ SAftlY

~

N~~

COOLWO SYSTttl AfTES LOCAL ACtUATlt SEAL NRR fIE~S AIEt tttttttA TUtttt ASS NEWCATEO VALUES EfAS f f AUX ttO LOW ACTUATtO AVNLA%4 t~ tA ACTlVATtA~

CTtie alan QNWlL TE~TS SANT f~

le~1 Sh IWHUAL TLWICW ftt~EQStt AUtteaaV ttAttUAL TlIE RF!

tct Qt TO HOT LORY SCtCA f> 150 fS lA f%275 fSIA 23ct<gtA NAWTAWWQ THOTC325 F NatlI TO HOT LEOS NEt COLO LEOS LEO ALE%I ALLWO fLCM TO COLO LSOS FUWOA Figure AUGHT CO. LONG-TERN COOLING PLAN St. Lucio 2 3,3,3-1 Nudeor Power Rag 389

1000 SIMULTANEOUS HOT SIDE/COLD SIDE INJECTION FLOW INITIATED AT 6 HOURS POWER 2750 MMT=102X OF NONINAL 800 ECCS FLOM=1 HPSI PUNP 600 UJ I

HOT SIDE/COLD SIDE 000 INJECTION FLOP RATE NET CORE 200 FLUSHING FLOW CORE BOIL-OFF RATE 10 TINE AFTER LOCA (HOURS) .

FLORIDA CORE FLUSH BY HOT SIDE INJECTION Flgu POWHcI UOHT CCL St. Luo4 2 FOR 9,8 FT COLD LEG BREAK 3 I3 I 3-2 MwSea Pcw Ptalt 390

35 SINULTANEOUS COLD/HOT SID ECTION INITIATED AT 6 HOURS POWER- 0 NW(T)

SOLUBILITY L I NIT 30 AT 20.0 PSIA 0 CORE FLUSH CORE FLUSH=

25 10 GPH CONSTANT Pl 20 rn I I ASSUNPTIONS:

tXI RCS=1.35 WT X CD a7 CD RWT=1.35 WT X A 15 SIT=1. 35 WT X BANT=12. 0 WT.X CD Pl Pl 10 CORE FLUSH=IHPS I FLOW-(BOILCFF)

CD 0

0 10 12 TINE AFTER LOCA (HOURS) w jg

,050 ASSUMPTIONS:

l. 1 HPSI PUMP ONLY INJECTS 2 RCS/SG COOLDOWN BEGINS AT 1 HOUR

.040 3. POWER = 2750 MWT

,03

,02 010 8 12. 16 20 RCS REFILL TIflE (HOURS)

RAKIDA Figure POWER OUGHT CO.

'St. Lucio 2 RCS REFILL TINE VE,RSUS BREAK AREA 3,3,3-0 Nude'awor Rant 392

RCS PRESSURE BREAK 2 AT w23 HRS 10 20 5 20 2 20 1 20 SIMULTANEOUS HOT LEG/ 0,5 20 COLD LEG INJECTION 0.2 20 COOLS CORE AND FLUSHES BORIC ACID 0.12 25 .

. FROM VESSEL 0.08 27 0.04 27 0.03 39 0.02 52 0.01 153 REFILL OF RCS DISPERSES 0.009 171 BORIC ACID THROUGHOUT 0.007 257 SYSTEM AND SGs ARE ABLE TO COOL RCS TO O.OOQ 450 SDC TEMPERATURE 0.001 1073 0.0002 1160 FLORlDA OVERLAP OF ACCEPTABLE LTC MODES Figure POWER@ UOH? CO.

N. Luoia 2 IN TERMS OF COLD LEG BREAK SIZE 3,3,3-5 Nucl ~ Power Plant 393

1200 10QO PONER = 2?54 Nv 102X OF NOMINAL FULL POMER

'00 600 400 RCS IS FILLED AT RCS IS NOT FILI ED 200 23 HOURS, AT 23 HOURS 0

Q 0,01 0,02 0,03 0,04 0,05 0;06

3.3.4 Containment erne eie 3.3.4.1 Containment Structure 554 >.1~01 8 The contaianent is designed to provide protection to the public from the consequences of a Iess-OfCoolant Accident (IDCA) up to and including a double-ended rupture of the largest reactor coolsnt pipe assuming unobstructed discharge from both ends coincident with the lose of offsite power and any single active ccarponent failure. The contaianent structure and the Ihgineered Safety Features ensure that the radiological earposure to the public resulting from such an occurrence is below the gxidelines established in 10CFR100. The spectrum of postulated accidents considered .

in deterndning the design containment peak pressure and temperature, the eubcanpartment peak pressure and the containment differential pressure used in the original anQyaia are aumnmied in Reference 9. - The apectrUm of break sizes was chosen to establish the upper bounds of containment reasure and temperature following a Design Basis Accident (IlBA). Por this 2700 Kft) analysis only the most limiting IDCA and Main Steam Iine Break (MHL8) cases were summed, as presented in Table 3.3.4-1.

The containment systems protect the public from the consequences of arg postulated break in the Reactor Coolant Syaten (RCS). Ke containment systems consist of the steel containment vessel surrounded b7 the Shield Building, and the Engineered Safety Peature ~tern which 1ncludes the Safety Injection System (Emergency Core Cooling System), the Containment '

Heat Removal System (Conta1nment Spray'ystem and Contairment Cooling System), the Shielding Building Ventilation System, the Containment Isolation System, and the Combustible Gas Control Syatan.

Por the purpose of the containment peak pressure/temperature ana~is following a IDCA, the most restrictive single active failure is a loss of one spray train of the Containment Heat Removal System resulting in minimum heat removal capability'. The operating portion of the Containment Heat Removal System is capable of reducing post-IDCA pressures to less than 50 percent of the calculated peak contaianent pressure w1thin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following this portniLated accident.

The peak containment pressure results from a KKB at 102 percent power with offaite power available. The most limiting single active failure was determined to be the failure of one Main Steam Isolation Valve (MSIV).

The peak containment temperature results from a MSLB at 102 percent power with offaite power available. The moat limiting single active failure is the failure of one tra1n of'he Containment Heat Removal Syatem or failure of one MSIV.

3 5412~at~~ 1~ 0i In the event of a postulated IDCA or KKB inside contaianent, the resultant release of'ass and energy raieee the temperature and pressure of the contairment atmosphere. The severity'f the resulting temperature and pressure peaks developed depends upon the nature, locations, and size of the postulated rupture. In order to establish the controlling conditions f'r containment design, the accident cases described in Table 3.3.4-1 were analzyed.

395

the pastulated rupture. Zn order to establish the oontrolling conditions ior contain<<ent design, the accident eases described in Table 3.3.4-1 werc analzyed.

The calculated transients follawfng a postulated accident are a direct consequence of the energy balance within the oantainment. Of particular f<<por tance are the fnitial eanditions postulated at the start af'he

<<ecident, the ability of the heat sinks within the containment to absorb energy during the aeoident, and thc capability of the Containment Heat No<<oval System to reduce the total energy within the containment thus bringing the contain<<ent heat sinks, sump water, and atmosphere into thermal equilibrium. The list ot fnitfal conditions is provided on Table 3.3 ~-2.

The containment pressure analysis fnyut data are based upon plant design features. i conservative prediction of consequences deter<<ining upper and lower bounding values of contain<<ent inftia)<

is assured by conditions, geometric parameters, and thermodynamic praperties, and by ayplying these values in the <<armer yroducing <<aximum yressure. and temperatures results.

The eantainment accident analyses arc yerformed using an Ebasco <<odified versian af the CONTEMPT-LT 26 computer eod'e.' Bescrfption of the computer oode and the Ebasco <<odification are eantained in Reference 9.

The <<echanfsm by which heat from the eantainment fs assumed to be re)ected to the autsidc environment during the accident is the follawing.

a. The heat fram the oontainment is re)ected to the Component Cooling Mater System (CCWS) by the heat transfer in the shutdown heat exchangers and containment fan coolers.

b. The CCWS supplies the shutdown heat exehangers and containment fan coolers with the maximum oooling water inlet temperature of 105 F.

e. The CCM heat exehangers serve as the <<eehanfsm by which heat is re5eeted ta the outside environment. hs yart at the accident heat removal system, each CCM heat exchanger is sized for one train of the Containment Heat Removal System available in the DBA LOCh case.

The rise in containment pressure and temperature oocurs until a heat balance fs reached. The rate of energy removal from the containment during reeireulatian is oaleulated using a Shutdown Cooling Heat Exchanger (SDCHX) overall heat transfer coefficient (UA) lower than design (unfoulcd), so as to maximize calculated eantainment yressure/temperature during reeireulatian. The maximum heat load on the SDCHX, assuming this lawer VA, occurs for the containment peak pressure DBA when the sump water temperature is at <<aximum and, henoe, a maximum temperature dfftcr ence exists in the SDCHX. Thc Component Coolfng Mater System is designed to accept .this peak heat load from the SDCHX and the heat generated by station emergency auxiliaries. This rise in yressure/temperature is reversed when the oombined SDCHX, containment fan cooler and structural heat removal rate become greater than the net heat addition to the containment.

A containment pressure/temperature analysis is performed for the LOCA assuming maximum safety inJection flow. For the purpose of this LOCA analysis, the ECCS and the Containment Heat Removal Systems are assumed to operate in the mode that maximized the containment pressure response. - For the Safety InJection System, maximum safety inJection flows are conservative for calculating the containment peak pressure response. St.

Lucie Unit 2 plant-specific analyses were conducted using both maximum and minimum ECCS flow rates in order to determine the'ost conservative case.

It was found that maximum ECCS flow was conservative. The reason for this is that maxmizing the core flooding rate has maximized the steam release rate to the containment.

For the Containment Heat Removal System, minimum system capacity is conservative for calculating the containment peak pressure response.

Therefore, the Containment Heat Removal System is assumed to be affected by the most conservative restrictive single failure which is assumed to be a <

loss of one containment spray train. One spray train is selected because the heat removal capability of one spray is greater than the capability'of two containment fan coolers. The loss of one diesel generator train is not the most restrictive single active failure since full safety inJection flows are not available.

Conservative trip setpoints for the Containment Spray Actuation System (CSAS) of 6.0 psig and for the Safety InJection Actuation System (SIAS) of 6.0 psig are utilized. The analysis considers a 1.15 second time delay after receipt of the trip setpoint to'.account for any equipment uncertainty or circuitry time delay.

The following describes the conservative assumptions made with respect to ESF system operations and parameters for the LOCA maximum pressure and temperature analyses:

a. For a discharge leg break, the contents of three safety inJection tanks discharge into the reactor vessel when the RCS pressure drops below tank pressure. The fourth tank is assumed to inJect into the broken leg and out to the containment. For a suction leg break, all four safety inJection tanks are assumed to inJect into the RCS.

b. All ECCS pumps operate at approximately run out flow (i.e., ECCS flow is assumed to be that corresponding to the instantaneous RCS pressure) until the start of recirculation, with 100 percent of the flow reaching the core.

c. One containment spray pump operates and sprays 2850 gpm of water into the containment until the= start of recirculation at a maximum refueling water tank temperature of 100 F.

d. One shutdown cooling heat exchanger operates during the recirculation mode of operation to cool the containment spray. The assumed UA of the heat exchanger is lower than the design minimum to minimize heat removal from the containment, and the heat is assumed to be supplied with cooling water flowing at exchange 2.41x10 lbs/hr with the maximum reoirculation component cooling water temperature 105 F.

397

e. The time until initiation of the recirculation mode is calculated on the basis of a minimum usable refueling water tank volume transferred to the containment of 305,600 gallons during the in3ection mode. At this time the low pressure safety infection pump is de-energized and the spray water is taken from the sump and cooled in the shutdown heat exchanger.

One containment spray pump starts spraying at 06.66 seconds after the analysis setpoint is reached. The spray flow rate reaches full flow 59.02 seconds after the analysis setpoint is reached.

g. Similarly four containment fan coolers are started 24.15 seconds after the containment reaches the analysis setpoint. The heat removal curves (Reference 9) assume a 40,000 acfm flow rate through each fan cooler unit with 1,200 gpm component cooling water a flow rate at the maximum temperature oi 105 F.

h. Oiisite power is not available.

The results of this analysis, presented in Table 3.3.4-1 show that the. peak post-LOCA containment pressure/temperature parameters are below the design conditions (i.e., 44 psig and 420 F).

3.3.4.1.2.2 Hain Steam Line Break

'he MSLB analyses are performed in order to assure the identification of the most severe cases for Containment Analysis. Since the steam generator feedwater ring is below the initial steam generator water level, feedwater break cases will result in liquid entrainment for all but the most trivial break sizes. For this reason, feedwater line break cases are always less severe than steam line breaks at the same power level and a spectrum of feedwater line break oases is not required.

Following a postulated MSLB, main steam isolation and main feedwater isolation are. initiated simultaneously by a HSIS from the Engineered Safety Features Actuation System. Feedwater flow is automatically terminated by

'he Main Feedwater Isolation Valves (MFIVs) or MFIV backup valves after receipt of a MSIS. The main steam isolation valves also close upon a MSIS. Table" 3.3.4-3 provides the valve closure times and the assumptions used for the MSLB analysis.

The feedwater spiking analysis was reviewed for the stretch power operation to demonstrate that the original analysis performed for the 100 percent power operation is conservative for the stretch power level as well.

The containment analyses for the MSLBs are performed using all . the containment initial conditions, heat sinks and methodology assumed for the LOCA analyses except for the following:

a. For the MSIV and MFIV failure oases, two containment spray pumps oper ate and spray 5,700 gpm of water at 100 F into the containment.

398

b, Since the aost severe MSLB containment transients ar e developed assuming the unavailability of offsite power, the containment sprays

~ re assumed to .start spraying 23.66 seconds after the containment pressure is oaleulated to reach the CSiS analysis aetpofnt. Full oontafnment spray flow ia reached 12.36 seconds later.

ee Consistent with the NSLB a'fngle aotfve failure assumptions, four containment fan coolers and two containment spray yumys operate for the NSIV and NIFV failure oases. For the Containment Heat Removal System train failure ease, two oontafnmeat fan coolers and one oontafnment spray pump are assumed to operate.

di Consistent with the assumption of availability of offsfte power, the oontafnment fan ooolers are assumed to be ia full operation 11. 15 seconds after the containment ia calculated to reach the SLLS analysis aetyofnt e

~e The vaporwump heat aad aaas transfers are oonservatively oaLtted for all NSLB anilyses.

Analyses have been performed to show that the eontafnment design pressure is f not .exceeded even f the following single actf ve failures are yostulated: (1) less of oae eeatafnment heat reaoval trafn (f.e., two fan coolers and one spray pump); (2) NSIV failure to olose; (3) MFIV failure to close. The assumptions for each ease are given below:

se 1 - Loss of One Containment Heat Removal Train Since postulation of a steam line'reak ylus the loss of one eontafamcnt heat removal train assumes a sfngle failure (e.g., loss of one diesel generator aet) ~ the MSIVs and MFIVs are yostulated to function for this ease. The aafn ateae inventory fn the line between the faulted steam generator noxxle and the nearest NSIV expands into the oontainment. The feedwater inventory between the faulted steam generator aad its NFIV fs assigned to flow fato the steam generator where it is relesed to the oontafnmeat. One eoatafnment spray trafn and two containment fan coolers are assuaed to operate.

Case 2 - MSIV Failure iaccident aiagle failure of one NSIV during a postulated main steam line break does not cause uncontrolled blowdowa of acre than one steam generator. The MSIV failure fa yostulated to occur at the faulted steam generator. Closure of the operational MSIV provides isolation of the intact steam generator. The NFIVs and both oontafament heat removal trafas (two containment sprays aad four containment fan . coolers) function for this ease. The steam inventory frow the faulted steam generator up to the closed NSIV oa the intact steam generator uy to the closed MSIV on the intact steam generator expands into the eontafnmcnt.

The feedwater inventory between the faulted steam generator aad its MSIV ia assumed to flow into the steam generator and ia released to the containment.

Case 3 - MFIV Failure A single failure of one MFIV during a postulated rrain steam line break accident is acacarmdated by closure of the backup feehmter isolation valves upon receipt of a MSIS. The MSIVs and both cccztainnent heat rerrr.wal tr~s (two containment sprays and fear containrrrent fan coolers)

The MFIV nearest to the faulted steam are postulated to cperate.

generator is postulated to fail. Steam in the steam line bebireen the break and the nearest MSIV expands to the containrrant. The feedwater inventory ~een the faulted steam generator and the feechrater backup valve flashes into the affected steam generator.

The feedwater flau rate to the faulted steam generator is determined using the calculated faulted and intact steam generator pressure responses, the feechrater pmrp characteristics and the feechater isolation or regulating valve fler coefficients.

3.3.4.1.2.2.1 Main Steam Line Breaks Results The peak containrrent pressure (43.70 psig)'s calculated to occur follcwing a MSLB at 102 percent pcver with a failure of cne .MSIV and offsite ~er available. The peak containnant tatperature (413.0 F) is calculated to occur following a MSLB at 102 percent pcver with offsite pcwer avai.lable System or the failure of one MSIV.

For all MSLBs analyzed, follcwiLng blowckwn of the ruptured steam generator unit, the RCS decay heat is transferred to the intact steam generator which, in turn, vents to the atnnsphere when its rrain steam safety relief valves.open. Therefore, there is no physical rrachanism for the release of bloods:m. The MSLB results, sumtaf.ized in Table 3.3.4-1, shvu that the predicted peak terrperature and pressure are within the design limits.

3 3.4.2 t Anal sis I

I't transients and jet 'l j inpingement forces by the effects of postulated ruptures containnent in which ruptures of high energy piping are postulated include the annular area between the reactor vessel and the prixrazy shield wall (reactor cavity), the enclosed volum belm the operating floor bcxux3ed bp the primary and seccm3ary shieM walls (secondary shield wall area) and the pressurizer area.

Analyses are performed to deterrrrine the mwurrum pressure which cauld be produced by a braken high energy line discharging mass and energy into the Calculated DBK di.fferential pressures are ccrrpared to the design differential pressure values used in the structural design of than design values.

400

Breaks are chosen for the an~eis based upon the maximum break'size that could be postdated given the structural stiffnese characteristics of the RCS and its supports and pipe restraints.

3.3.4.2.2 Desi Evaluation The subcanpartment pressurization effects are dependent on the blowdown energy release rates. In order to provide adequate conservatism for design evaluation, the following methodology ie used to generate short duration mass and energy release rates-

a. Subcooled and low quality break flow are canputed using the Henry-7'auske correlation with a discharge coefficient of 1.0.

b. Break flow with quality above approximate+ 6.0 percent ie computed using the Moody critical flow correlation with a discharge coefficient of 1.0.

c. The momentum flux- terms are anitted when solving the conservation of manentum equation for flows within the Reactor Coolant System.

d. Initial RCS conditions are at 102 percent of naninal full pLer conditions.

e. RCS volumes are increased over nominal values.

The pressurizer water level is mimed to be above the normal. full power operating water level.

Mass and energy'elease data was generated for 2700 Kft conditions. The results indicate only a minor increase as compared to the original data provided for the same breaks at 1K'oad (2560 MVt)-

Por a similar mass and energy release increase, the containment peak pressure'calculated for 2700 Ktt resulted o~ in a minor rise (<.5g).

Taking into account the identical methodology used for calculating the containment peak pressure and the subc ent loading and, also considering the existing design margins >1K'!') of the containment subcanparhnents (Reference 1), it is concliBed that for core power conditions of up to 2700 Kft, the subconlipMMent loading wi11 remain below the desigp values.

3 3.4.3 ro n Build ie The hydrogen build-up inside contaianent is controlled by the Containment Canbustible Gas Control System. This system provides the capability to monitor and maintain igrdrogen concentrations within safe. limits after a IOCA and is made-up of the following subsystems: containment 1grdrogen

~zers, containment hydrogen recanbiners'nd containment hydrogen purge.

The design bases and the system functional evaluation, aa well as the hydrogen generation ~sis methodo1ogy ie described in Reference P.

increased power level impact on the post IOCA hydrogen bui3P-up inside The containment has been ized.

401

number of 4hanges have been incorporated into the current model, including an updated long term temperature transient, increased radiolytic hydrogen due to the increased reactor poorer level ~ additional zinc-based paint, additional galvanized steel and additional aluminum ladders'he analysis proved that the Containment Combustible Gas Control System is capable without any modification of preventing the hydrogen gas concentration inside containment from exceeding the ?ewer flmmability limit of four volume percent, therefore complying with the existing system design criteria.

402

%VILE 3 3e4-1

~~ted ~Seats an5 Results for Results Peik .

CIaperature Dnuble ended soatj cec lag slot, 9.82 ft area with maxim safety in~en 42.70 265.8 f~

MKB 7 6257 ft2 area at 102% pane with failure II&

tmdn 43.20 413.9 7.6257 ft2 area at, 102% pc@mr with failure of HSIV 43.70 413.0 403

TABLE 3.3.4-2 Initial (ancU.tions for Containmmt Peak Pressure Temperature Analysis Value Reactor Coolant Reactor Pnrer Level, MÃt( ) 2774 Max. Cold Leg Coolant Tenmprature, F 552 Pressurizer Pressure, psia 2,250 Mass of Reactor Coolant System Liquid, I3m 478,388 Mass of Reactor Coolant System Steam, llm 4,410 Liquid Plus Steam Energy, 10 8IU 277.58 Cont~ant Pressure, psig 0.4 Temperature, F 120 Relative Humidity, 8 45 Cmponent Cooling Water Tarperature, F 105 Refueling Water Storage Pool Temperature, F Net Free Volum (Miniamn); xl0 ft 2.506 Stored Water Usable'efueling Water Storage Pool (Minim), gal 305,600 Safety In)ection Tanks, h

ft 6,156 Hates:

(1) At design ovezpnrer to 102 percent and norrral liquid levels, plus an additional alliance of 20 hÃt for heat addition by the RCS pumps.

404

TABLE 3 '.4-3 Valve Closure Times and Assumptions Used in MSLB Analysis Valve Closure Times (from recei t of si nal)

1. MSIV (I-HCV-08-1A and I-HCV-08-1B) closure time, sec 5.6 2 MFIV (I-HCV-09-1A and I-HCV-09-2A) closure time, sec 4.0

3. Backup feedwater isolation valve (I-HCV-09-1B, 2B) closure time, sec 4 ~0 Reactor trip on low steam generator pressure, psia 510

5. Reactor trip on high containment pressure, psig 6.0

6. Instrumentation delay time, sec 1 ~ 15 Assum tions

1. Credit is not taken for the coastdown of the main feedwater pumps or condensate pumps in the MSLB analysis. Therefore, no degradation of the feedwater flow occurs until the closure of the main feedwater isolation or backup valves.

II

2. Offsite power is assumed to be available for the analysis. Availability of offsite power allows the continuation of reactor coolant pump and feedwater pump flows. Maintaining reactor coolant and feedwater pump flow maximizes

'the rate of primary to secondary heat transfer which maximizes the rate of mass/energy release.

405

3.4 H draulic (Blcwdown) Loads on the Reactor Vessel Internals Under Faulted Conditions 3.4.1 Introduction Dynamic hydraulic analyses have been performed to determine blowdown loads on the reactor internals and fuel caused by postulated LOCA (Loss of Coolant Accident) occurrenoes. These blowdown loads, for 2700 MWt conditions, were then oompared to those previously determined for St. Lucie Unit 2 Cycle 1 (Reference 1) which henceforth will be referred to as the reference cycle. A brief desoription of these analyses is presented below.

3.4.2 Anal ical Procedure The CEFLASH-¹B computer code (Reference 2) predicts the reactor pressure vessel pressure and flow distribution during the subcooled and two-phase portions of the blcwdown period of the 'OCA. The equations for conservation of mass, energy and momentum along with a representation of~

the equation of state are solved simultaneously in the node and flowpath network which models the primary reaotor ooolant system.

The CEFLASH-¹B computer oode is a modified version of the CEFLASH-4A code ".

(References 3 to 5). The CEFLASH-4A and WB computer codes have been approved by the NRC (Reierenoes 2, 6 and '7). The capability of CEFLASH<<4B to predict experimental blowdown data is presented in Reference 2.

3.¹.3 Initiatin Events The initiating events for the subsequent rapid blowdown are breaks in either the hot or cold leg piping. - The mechanistic pipe breaks considered for the 2700 MWt analyses were identical to those defined for the reference cycle analyses presented in Reference 1. These break sixes and looations are given below.

200 in. break at the reactor~vessel inlet nozzle (cold leg) 135 in. break at the reaotor vessel outlet nozzle (hot leg) 1000 in. break at the steam generator inlet nozzle (hot leg) 3.4.4 H drod amic Forcin Functions The hydrodynamic forcing functions that occur during a postulated LOCA result from transient pressure, flow rate and density distributions throughout the primary reactor coolant system. As noted above (Section 3.4.1), the primary system is modeled with the CEFLASHAB code. This code employs a node-flow path network to represent the fluid distribution. The blowdown loads model uses a non-equilibrium critical flow correlation for computing the subcooled and saturated critical fluid discharge through the break.

Pre-blowdown, steady state oonditions in the reactor ooolant system are established through the use of speoified input quantities. Thus, for the present analysis appropriate oonditions (power, flowrate and fluid temperatures) were input to define the 2700 MWt operating oondition.

406

3.4.5 Parameters of Interest The hydrodynamic parameters of interest for an assessment of blowdown loads are given in Table 3;4-1. Also shown are the break locations (hot or cold leg) for which these parameters are most signifioant. A brief description of these parameters is given'below.

3 4.5.1 Lateral Pressure Difference Across Vessel Annulus For a break in an inlet line the transient pressure distribution in the reactor vessel annulus is highly asymmetric for a brief period of time.

This asymmetric distribution produces a net lateral force on the core support barrel which transfers to the core by structural interaction. For a break in an outlet line the decompression wave propogates down through the inside of the. core barrel and up through the annulus in a 'fairly syaxaetric fashion. Hence, any lateral load on the core barrel is minimized.

3.4.5.2 Lateral Dra Force on Control Element Assembl (CEA) Shrouds t

During normal operation, the reactor coolant flows axially through the core into the upper guide structure. Within the upper guide structure, . the coolant flow changes direction so that it exits radially through the hot leg nozzles. During a LOCA, the transverse flow of the coolant across the CEA shroud can give rise to loads which induce deflections in these shrouds.

The transverse drag forces were determined from flow model experiments which were geometrically and dynamically similar to the full-scale upper guide structure design. The measured experimental model forces were scaled up to represent the actual forces on the. upper guide structure using the computed transient flow rate and density information.

The drag force of the flowing fluid across the CEA shrouds in the upper guide structure and through the hot leg nozzles also depends on the break location. For a break in an inlet line the flow across the CEA shrouds and into the hot leg (in the broken primary loop) will not rise significantly above the steady state value before it begins to decrease due to fluid depletion. Thus, the transient drag force will not be excessive. The flow across the CEA shrouds and the resultant drag force in the direction of the intact RCS loop will decrease from the steady state value.

For a break in a hot leg (outlet line) the flow r ate across the CEA shrouds and into the broken leg will increase until the fluid in the vessel is depleted. This incre'ased flow rate will increase the drag force acting on the CEA shrouds. The flow in the opposite (intact) hot leg will decrease along with the resultant drag force.

It is worth noting that for a large break (>0.5 ft ) there is no necessity for CEA insertability as negative reactivity is provided by the moderator voiding during blowdown and the boric acid content of. the reflood water. Hence, the possibility of CEA hangup due to lateral drag forces on the CEA shrouds will not impact the course of the accident.

407

3.4.5.3 Pressure Difference Across Core Su ort Barrel (CSB) Wall The pressure difference across the wall of the CSB oan, in general, be significant for breaks in either the inlet or outlet legs. An inlet leg break will, of oourse, result in an azimuthally asyametric CSB load distribution with respect to the location of the affected leg. This load will also vary with axial position along the CSB. An outlet leg break will result in a azimuthally symmetric CSB wall load. It will, of course, vary axially.

3.4.5.4 Core Axial Pressure Difference

.The axial pressure difference in the oore can be significant for either inlet or outlet leg breaks. This is a function of break size and proximity to the vessel 3 4 6 Results The analytical results are desoribed below. Pertinent results for the cases run at 2700 MWt are compared to the reference cycle results for which complete structural response analyses have been performed.

3.4.6.1 Vessel Inlet Break An analysis was performed for a postulated 200 in mechanistic pipe break at the reactor vessel inlet nozzle.

Figure 3.4-1 shows the transient'ressure difference across the vessel annulus at the elevation oi the centerline of the nozzles. This function is equal to the pressure in the annulus adjacent to the break cold leg nozzle minus the pressure in the annulus at 180 from the break location. This particular pressure difference exhibits the largest transient magnitude of all pressure loads across the vessel annulus. It is seen'rom 'Figure 3.¹-1 that the results for the 2700 MWt case are very similar to the referenoe cycle results.

Figure 3.4-2 shows the transient pressure difference across the wall of the core support barrel (CSB) at the elevation of the inlet nozzle centerline.

This function is equal to the pressure inside the CSB (upper plenum) minus the pressure'n the annulus ad)scent to the broken cold leg nozzle. It is seen from Figure 3.4-2 that for both 2700 MWt and the reference cycle the results are very similar for the portion of the transient when the loads are greatest. There are some small differences later in time (>0.2 second) when the magnitudes are considerably below their peak values.

Figure 3.4-3 shows the transient axial pressure difference across the core. It is seen from this figure that there is exoellent agreement between the 2700 MWt and reference oycle results for the period of time

'hen the loads are relatively high (<0.2 second). At later times, when the loads are no longer high, there are some differences.

3.4.6.2 Vessel Outlet Break An analysis was performed of the postulated 135 in. mechanistic pipe break at the reaotor vessel outlet nozzle. Because of the relatively small size of this break the resultant blowdown loads are not very large. A comparison between the referenoe cycle and the 2700 MWt results follows.

408

Figure 3.4-4 shows the product of flow squared and specific volume. in the nozzle of the broken'ot leg. This parameters relates to the drag force on the individual control element assembly (CEA) shrouds (in the upper guide structure) by means of an experimentally based coefficient (see Section 3.4.5.2). It is seen from, Figure 3.4-4 that the drag parameter rises rapidly following the pipe break and then decreases gradually as the fluid inventory in the vessel and primary system is lost through the break. The drag parameter is very similar for both the stretch power and the reference cycleo Figure 3.4-5 shows the pressure difference across the wall oi the CSB at the outlet nozzle centerline elevation. The reference cycle and the 2700 MWt results are similar. Both results are small compared to Figure 3.4-2 ior the inlet break.

Figure 3.4-6 shows the core axial pressure difference. Again, both the reference cycle and the 2700 MWt results are similar.

3.4.6.3 Steam Generator Inlet Break An analysis was performed oi a postulated 1000 in mechanistic pipe break at a steam generator inlet nozzle.

Figure 3.4-7 shows the transient pressure difference across the wall of the core support barrel at the elevation of the inlet nozzle centerline. There is generally good agreement between the reference cycle and the 2700 MWt results'.

Figure 3.4-8 shows the transient core axial pressure difference. There is generally good agreement between the reference cycle and the 2700 MWt results during the period of time when the magnitude of the loads are the greatest (<O.t second). For the time period from 0.1 second to 0.3 second there is a reasonable agreement in the trend of the data with the reference cycle results showing the greater peak magnitudes. Beyond 0.3 second the data are in good agreement.

Figure 3.4-9 shows the product of flow squared and specific volume in the nozzle of the break hot leg. As noted above, this parameter relates to the drag force on the individual CEA shrouds in the upper guide structure. As seen from Figure 3.4-9, the peak magnitude calculated for this param'eter occurs for the reference cycle. Subsequent, lesser peaks are greater for the 2700 MWt case.

3.4.7 .Conclusions A comparison has been made of the blowdown loads parameters of interest for both the reference cycle and the 2700 MWt oases. The comparison revealed good agreement for most of these parameters. This good agreement supports the conclusion that the 2700 MWt results are acceptable. Furthermore, response, for stretch power, is not warranted. An exceptio6 toa'tructural the generally good agreement was ~oted ior the transverse drag parameter (Figure 3.4-9) for the 'l000 in break at the steam generator inlet nozzle. For the case shown the peak amplitude occurred for the reference cycle case for which a structural response analysis was performed.

409

Table 3.4-1 Blowdown Loads-Pareneters of Interest Significant Break Pereoeter ~Hot Le ~Cold Le Lateral pressure difference across vessel annulus No Yes Lateral drag force on CEA shrouds Yes Pressure difference across core support barrel wall Yes Yes Core axial pressure difference Yes Yes 410

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4 0 TECHNICAL SPECIFICATION CHANGES Page 1 TABES 4-1 ST+ LUCIS UlfIT 2 TECHNICAL SPECIFICATIOS AND BASES CHA1ICES 8 cification 2-1 2.1.1.2 Change peak linear heat to Peak linear heat to centerline melt centerline melt limit from limit is raised to the calculated .

21 ' kw/ft to 22.0 kw/ft limit for Cycle 2, as described in Section 2.2.*~

2-3 Figure 2.1-1 Replace this figure with Thermal limit lines are being changed revised figure. to reflect analysis at 2700 NfT, Technical Specification radial peaking factors and the implementation of margin recovery programs.

2-4 Table 2.2-1 The Containment Pressure -. This change is being made so that the P

High Trips Allowable value trip setpoint is consistent with the is being reduced from 5.0 . assumptions made to the containment psig to 4.1 psig. pressure High - High trip setpoint in the LOCA containment pressure and the pre-trip steam line inside containment analyses< Section 3.3.4.

2-5 Table 2.2<<1 Change design reactor coolant All analyses sensitive to minimum flow flow from 370,000 gpm to requirements'ere performed assuming 363>000 gpm on Footnote (~). a 363,000 gpm minimum guaranteed flow rate 2-9 Figure 2.2-3 Replace figure with The TN/LP LSSS is being changed to revised figure. reflect analysis at 2700 NtT, Technical Specification radial peaking factors> and the implementation of margin recovery programs.

2-10 Figure 2.2-4 Replace figure with The TM/LP LSSS is being changed to revised figure. reflect'nalysis at 2700 MMT, Technical Specification radial peaking factors, and the implementation of margin recovery programs.

~Refers to sections contained in Reload Safety Report.

Page 2 of 7 Remarks B2-1 B2 ~ 1 ~ 1 Change minimum DNBR limit The value of DNBR, which corresponds to the from "1.20" to read "an 95/95 criteria, changes slightly from acceptable limit". cycle to cycle due to the application of statistical uncertainty analysis> specific values of the DNBR limit are being deleted to avoid the necessity of cycle-by-cycle Tech. Spec. Revisions.

B2-1 B2 F 1.1 Change statement on DNBR The value of DNBR, which corresponds to the B2-4 B2.2.1 from "1.20" to "the acceptable 95/95 criteria, changes slightly from minimum DNBR limit". cycle to cycle due to the application of uncertainty analysis> specific 'tatistical values of the DNBR limit are being deleted to avoid the necessity of cycle-by-cycle Tech. Spec. revisions.

B2-2 Figure B2.1-1 Replace figure with Pigurc is being changed to reflect higher revised figure. radial peaking.

3/4 1-3 3/4.1.1.2 ~ Change shutdown margin for The shutdown margin is being increased Mode 5 from 2.0% delta k/k to reflect the assumptions used in the to 3.0% delta k/k. boron dilution event, Section 3.2.4.4.

3/4 1-8 3.1.2.2 Change shutdown margin from To be consistent with Technical 3/4 1-10 3.1.2.4 2.0% delta k/k to Specification 3/4.1.1.2.

3/4 1-12 3.1.2.6 3.0% delta k/k.

3/4 1-14 3.1.2.8 Change shutdown margin at To be consistent with Technical 200'rom 2.0% delta k/k Specification 3/4.1.1.2.

to 3.0% delta k/k.

~ ~ /"

Page 3 3/4 1-18 3.1.3.1 Reduce number of CEA regulating Due to change in number of CEA 3/4 1-19 groups from 6 to 5 in Items b.2 regulating banks.

3/4 1-19a and h. of the Action Statement.

Reword Item d. to reflect use of figure shying dropped CEA recovery time vs. measured Fr.

Remove Footnote (0) vhich Change to reflect higher radial peaks shomd the time constraints used in analysis to support increased on a single CEA drop. This is dropped CEA recovery time flexibility.

nest contained in Item d. which includes a figure shcnrlng

'ropped CEA recovery time

. vsse measured Fr.

Resequence Items e. through g.

to reflect addition of ne~

Item e.

3/4 1-24 3.1.3 ' Change CEA drop time from This reduced time is consistent with 3.0 seconds to 2.7 seconds. plant measurements.

3/4 1"28 Figure 3 '-2 Replace figure with The PDIL is being changed to accanmodate revised figure. the ne~ CEA rod pattern.

3/4 2-4 Figure 3.2-2 Replace figure with LHR Ex-core LCO is being revised to reflect revised figure. analysis at 2700 Mitt, Technical Specification radial peaking factors, and the implementation of margin recovery programs.

3/4 2-5 Figure'3 ' 3 Replace figure with Ailcnrable combinations of thermal pcwer and revised figure. Fr, FxyT are being revised to reflect analysis at 2700 MNt and the implementation of margin recovery programs.

Page 4 of 7 S bificatiem 3/4 2-7 3.3.2 Change the PT>> limit The value for PxyT limit is raised to frem 1.60 to 1.75. reflect the value used in the safety analysis.

3/4 2-9 3 2 ' Change the PTr limit Tha value for PTr limit is raised to reflect from 1.60 to 1.70. the value used in the safety analysis.

I 3/4 2-9 4.2.3.2 Delete all references to Rod boe penalties have been accoeeodated in 3/4 2-11 Table 3.2-1 rod bo~ penalty. the revised DHBR limit of 1.28.

3/4 2-12 Pigure 3.2 Replace figure with The DNB-IA:0 is being changed to reflect revised figure. analysis at 2700 Nit, ReactoL Coolant Pleat of 363,000 gpm, Technical Specificatien xadial peaking factors, and the implementation of margin recovery programs.

3/4 2-15 Table 3.2-2 Increase upper bound of Upper bound cold leg temperature change cold leg temperature reflects safety analysis assumptions from 548'P to 549"P. performed for Cycle 2.

Decrease reactor coolant hll analyses sensitive te minimum flcnr

.flcnr rate from 370>000 requirements mre performed assuming gpm to 363,000 gpm. a 363,000 gpm minimum guaranteed flcnr rate.

3/4 3-6 Table 3.3-2 Change Centainmant Pressure- This reduced time is consistent with High response time from 1.55 plant measurements.

seconds to 1.15 seconds.

3/4 3-17 Table 3.3-4 Changed containment spray This change ~s made to be consistent en Containment Pressure arith assumptions in the High - High Trip Setpoint from containment pressure analysis.

9.30 psig to 5.40 psig and the elle@cable value from 9.40 psig to 5.50 psig.

Change the Containment Pressure This change vas necessary because of the High Trip Setpoint from 5.0 change made to the Containment Pressure

,. psig to 4.7 psig and the High - 1Qgh Trip Set Point.

allowable value from 5.10 psig to 4.80 psig.

Page 5 of 7 Reaarks 3/4 3-20 Table 3.3-5 Change Feedwater Isolation This change is being made to incorporate Response Time from <5.35/5.35 the specified valve closing time and to to <5.15/5.15 for both eliminate the 0.25 second additional Containment Pressure High conservatism that was assumed in and Steam Generator Pressure- Cycle l.

Low.

3/4 4-9 3.4.3 Change minimum and maximum This change 'is being made to be consistent pressurizer indicated level with a new pressurizer level program from 65$ to 68.0%. and assumptions made in the excess charging event, Section 3.2.5.1.

3/4 7-1 3/4.7.1 Replace these pages with 'hanges made to allowable power values 3/4 7-2 Table 3.7-1 revised pages. reflect analysis at 2700 MWt. Format of 3/4 7-3 Table 3.7-2 specification has been changed to improve clarity.

3/7 7-10 3.T.1.6 Change full closure times of These changes reflect appropriate closure 5.6 'seconds and 5.35 seconds times for the main feedwater isolation valve both to 5.15 seconds. (5.15 seconds was assumed in peak containment pressure analysis.)

B3/4 1-1 B3/4.1.1.1 6I Change the required shutdown The shutdown margin is being increased B3/4.1.1.2 margin with Tavg < 200'rom- to reflect the assumptions used in the B3/4 1-2 B3/4.1.2 2.0$ delta k/k to 3.0% boron dilution event, Section 3.2.4.4.

delta k/k.

r iy ~ I Page 6 of 7 8 cificatim B3/4 1-4 B3/4.1.3 Remove wording indicating at Change wording, since power levels at what power levels a DNBR SAPDL which a DNBR SAPDL violation may occur violation could occur, and could vary slightly from cycle to cycle.

clarify the wording on how this potential violation is eliminated.

Increase steady-state radial peak from.Fr 1.60 to PrT 1 70 B3/4 1-4 B3/4.1.3 Change actual radial peak for These changes reflect the assumptions additional margin from utilized in the single drop CEA analysis PTr ~ 1.50 to PTr<1.70. found in Section 3.2.4.3.

Change Item 5 from a 30 minute misalignment time for an FT < 1.50T to 60 minutes for an Pr< 1.55.

B3/4 2-2 B3/4.2.2 Delete last paragraph which Rod bow penalties have been accommodated B3/4 2 3 s discusses rod bow penalties, in revised DNB limit of 1.28.

B3/4 ' 4 and delete table on rod B3/4 2-3 Table B3/4.2-1 bow penalties.

B3/4 2-2 B3/4.2.5 Change "minimum DNBR limit of The value of DNBR, which corresponds to the

> 1.20 to "an acceptable 95/95 criteria, changes slightly from minimum DNBR". cycle to cycle due to the application of statistical uncertainty analysis; specific values of the DNBR limit are being deleted to avoid the necessity of cycle-by-cycle Tech. Spec. revisions.

Pa of 7 8 ficaticm B3/4 7-1 B3/4.7 1 1 Replace page with revised page. Changes made to allowable power values reflect analysis at 2700 NNt. Format of specification has been charged to improve clarity.

5-3 5.3 1 Change "...236 fuel rods This new statement is appropriate if clad..." to "...236 fuel assemblies with poison rods are loaded and poison rod locations. into the core. Cycle 2 will contain such All fuel and poison rods assemblies.

are clad..."

Change "...a maximum total The weight of 1698.5 grams is a Cycle 1 weight of 1698.5 grams uranium" maximum weight. By wording it to "...approximately 1700 approximately 1700 grams, variations in grams uranium". loading weights can be tolerated.

5>>1 5.2.1 Change containment net free Chahge in this value represents a more volume from 2;5 x 106 ft3 detailed analysis of the containment net to 2.506 x 106 ft3. free volume.

5-3 5.3.2 Increase the number of full- Bight full length CEAs are being added into length control element vacant part length CBA locations.

assemblies (CEAs) from 83 to 91;

I P

l

5.0 REFERENCES

References for Section 1.0 1 ~ St. Lucie Nuclear Power Plant Unit Two, Final Safety Analysis Report in Support of Docket No. 50-389, License No.'PF-16.

References for Section 2.0 St. Lucie Nuclear Power Plant Unit Two, Final Safety Analysis Report in Support of Docket No. 50-389, License No. NPF-16.

20 CENPD-187, "CEPAN Method of Analyzing Creep Collapse of Oval Cladding,~

June 1975.

3~ CENPD-198-P, "Zircaloy Growth In Reactor Dimensional Changes In Zircaloy 4 Fuel Assemblies," December 1975, Including Supplement 1, <

Deoember 1977 and Supplement 2, November 1978.

CENPD-139-P-A, "C-E Fuel Evaluation Model Topical Report," July 1974.

5. CEN-161(B)-P, "Improvements to Fuel Evaluation Model, July 1981.

6. Letter, R. A. Clark (NRC) to A. E. Lundvall, Jr. (BGIE), "Safety Evaluation oi CEN-161 (FATES 3)," March 31, 1983.

7~ CEN-133(B), "FIESTA - A One-Dimensional Two-Group Space Time Kinetics Code for Calculating PMR Scram Reactivities", November 1979.

8. CENPD-153-P, Rev. 1-P-A, "Evaluation of Uncertainty in the Nuclear Power Peaking Measured by the Self-Powered, Fixed In-Core Detector System", May 1980.

9. CENPD-266-P-A, "The ROCS and DIT Computer Codes for Nuclear Design",

April 1983.

10. M. R. Cadwell, "PDQ-7 Reference Model", MAPD-TM-678, January 1968.

CENPD-161-P, "TORC Code, A Computer Code for Determining the Thermal Margin of a Reactor Core," July 1975.

12 ~ CENPD-162-P-A, "Critical Heat Flux Correlation for C-E Fuel Assemblies with Standard Spaoer Grids Part 1, Uniform Axial Power Distribution,"

April 1975.

13. CENPD-206-P, "TORC Code, Verification and Simplified Modelling Methods," January 1977.

14 ~ CEN-191(B)-P, "CETOP-D Code Structure and Modeling. Methods for Calvert Cliffs Units 1 and 2," December 1981.

15 CEN-123(F)-P, "Statistical Combination of Uncertainties, Part 2,"

February 1980. /

16. CENPD-225-P-A, "Fuel and Poison Rod Bowing," June 1983.

428

References for Section .2 1 ~ Caruthers, G. F. and Green, P. K., Radioactive Behavior in the Reactor Coolant System During Transient Operation, C-E Topical Report, CENPD-

~180 March 1976.

2o CE Setpoint Methodology, C-E Local Power Density and DNB LSSS and LCO

~1-P March 1982.

3~

Deoember 1979; Part 2, January 1980; Part 3, March 1980.

"STRIKIN II, A Cylindrical Geometry Fuel Rod Heat Transfer Program,"

98

5. "CETOP-D Code Structure and Modeling Methods for Calvert Cliffs 1 and 2,< CEN-191(B)-P, December 1981 ~

6.

Appendix A, December 1980.

7o St. Lucie Nuclear Power Plant Unit Two, Final Safety Analysis Report in Support of Docket No. 50-389, License No. NPF-16.

8. Not used

9. McBeth, R. V., "An Appraisal of Forced Connection Burnout Data," Proc.

Instn. Mech. Engrs., Vol. 180, Pt3C, PP 37-50, 1965%6.

10 ~ Leis, D. H., "An Experimental Investigation of Forced Convection Burnout in High Pressure Water. - Part IV, Large Diameter Tubes at about 1600 psia," A.E.E.W. Report 'R 479, 1966.

11. CENDP-190A, "CEA Egection, CE Method for Control Element Assembly Egection," July 1976 12 ~ H. C. Brassfield, et. al., "Recommended Property and Reactor

'EMP-482, Kinetics Data for Use in Evaluating a Light Water-Cooled Reactor Loss-of-Coolant Incident Involving Zircaloy-4 or 300-SS, Clad UO2t," AprilD 1968.

13 ~ Idaho Nuclear Corporation, Monthly Report, Ny-123-69, October 1969.

14 ~ Idaho Nuclear, Corporation, Monthly Report, Hai-127-70, March 1970.

15 ~ CENPD-183, "CE Methods for Loss of Flow Analysis," July 1975.

16. Letter, Robert E. Uhrig, (FP&L) to Viotor Stello (NRC), dated February 22, 1979, "St. Lucie Unit 1 Docket No. 50-335 Proposal Amendment to Facility Operating License DPR&7".

17 St. Lucie Nuclear Power Plant Unit One Final Safety Analysis Report in Support of Docket No. 50-335, License No. DPR-67.

429

References for Section .3 1~ Acceptance Critei ia for Emergency Core Cooling Systems for Light-Water Nuclear Poser Reactors, Federal Register, Vol. 39, No. 3 - Friday, .

January 4, 1974.

20 CENPD-132, "Calculative Methods for 'the C-E Large Break LOCA Evaluation Model," August 1974 (Proprietary).

CENPD-132, Supplement 1, "Updated Calculative Methods for the C-E Large Break LOCA Evaluation Model," December 1974 (Proprietary).

CENPD-132, Supplement 2, "Calculational Methods for the C-E Large Break LOCA Evaluation Model," July 1975 (Proprietary).

3~ CENPD>>133, "CEFLASH-4A, A FORTRAN IV Digital Computer Program for Reactor, Blowdom Analysis," April 1974 (Proprietary).

P CENPD-133, Supplement 2, "CEFLASH-4A, A FORTRAN IV Digital Computer Program for Reactor Blovdown Analysis (Modification)," December 1974 (Proprietary).

CENPD-134, "COMPERC-II, A Program for Emergency Refill-Reflood of the Core," April .1974 (Proprietary) ~

Supplement 1, "COMPERC-II, A Program

'ENPD-134, for Emergency Refill-Reflood of the Core (Modification)," December 1974 '

(Proprietary).

5. CENPD-135, "STRIKIN-'II, A Cylindrical Geometry Fuel Rod Heat Transfer Program," April 1974 (Proprietary).

CENPD-135, Supplement 2-P, "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program (Modification)," February 1975 (Proprietary).

CENPD-135, Supplement 4-P, "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program," August 1976 (Proprietary).

CENPD<<135, Supplement 5-P, "STRIKIN-IZ, A Cylindrical Geometry Fuel Rod Heat Transfer Program," April 1977 (Proprietary).

6. CEN-161 (B), "Improvements to 'uel Evaluation Model," July, 1981 (Proprietary).

70 Letter, R. A. Clark (NRC) to A. E. Lundvall, Jr. (BG8E), "Safety Evaluation of CEN-161(FATES-3)," March 31, 1983.

8. CENPD-138, "PARCH, A FORTRAN IV Digital Program to Evaluate Pool Boiling, Axial Rod and Coolant Heatup," August, 1974 (Proprietary).

CENPD-138> Supplement 1, "PARCH, A FORTRAN-IV Digital Program to Evaluate Pool Boiling, Axial Rod and Coolant Heatup (Modifications),"

February, 1975'(Proprietary).

CENPD-138, Supplement 2, "PARCH, A FORTRAN IV Digital Program to Evaluate Pool Boiling,. Axial Rod and Coolant Heatup (Modifications),"

January 1977 (Proprietary).

St. Lucie Nuclear Power Plant Unit Two, Final Safety Analysis Report in Support of Docket No. 50-389, License No. NPF>>16, Section,Nos. 6.2.1.5 and 6.3.3.2.

10 CENPD-137, "Calculative Methods for the C-E Small Bre'ak LOCA Evaluation Model," August 1974 (Proprietary).

CENPD-137, "Calculative Methods for the C-E Small Break LOCA Evaluation Model," Supplement 1, January 1977 (Proprietary).

11 ~ CENPD-133, Supplement 1, "CEFLASH<<4AS, A Computer Program for Reactor Blowdown Analysis of the Small Break Lossmf-Coolant Accident," August 1974 (Proprietary).

CENPD-133, Supplement 3, "CEFLASH-4AS, 'A Computer Program for Reactor Blowdown Analysis of, the Small Break Loss-of-Coolant Accident," January 1977 (Proprietary).

r

12. CENPD-254-P-A, "Post-LOCA Long Term Cool'ing Evaluation Model," June 1980,

13. R. L. Baer (USNRC LWR Branch) to A. E. Scherer (C-E), "Staff Evaluation of Topical Report, CENPD-254-P," July 30, 1979.

References for Section .4 1 ~ St. Lucie Nuclear Power Plant Unit Two, Final Safety Analysis Report in Support of Docket No. 50-389, License No. NPF-16; 20 Combustion Engineering, Inc., "Method for the Analysis of Blowdown Induced, Forces in a Reactor Vessel," CENPD-252-P-A, July 1979;, December 1977 (proprietary) ~

3~ Combustion Engineering, Inc., "CEFLASH<<4A: A 'Fortran-IV Digital Computer Program for Reactor Blowdown Analysis," CENPD-133P, August 1974 (proprietary).

4~ Combustion Engineering, Inc., "CEFLASH-4A: A Fortran-IV'igital Computer Program for Reactor Blowdown Analysis (Modifications)," CENPD-133P, Supplement 2, February 1975 (proprietary).

5. A. E. Scherer, Licensing Manager (C-E) Letter to D. F. Ross, Assistant Director of Reactor Safety Division of Systems Safety, LD-76-025, March 1976 (proprietary).

6. O. D. Parr, Chief Light Mater Reactor Pro)ect Brack 1-3, Division of Reactor Licensing (NRC), Letter to F. M. Stern, Vice President of Prospects (C-E), June 1, 1975 70 Kniel, Chief Light Mater Reactors Brack No. 2, Letter to A. E.

Scher er, Licensing Manager (C-E), August 1976,'Staf f Evaluation of CENPD-213) .